BP Drilling Manual

BP EXPLORATION

Petrotechnical Shared Resource

Guidelines for Drilling Operations (UK Operations) (GEN, SEMI, JAK and FIX Categories Only)

PSR-W06

UK Operations GUIDELINES FOR DRILLING OPERATIONS SUBJECT:

MASTER INDEX OF GUIDELINES FOR DRILLING OPERATIONS

Index Prefixes 0000

Safety and Administration

1000

Drilling

2000

Casing and Tubing

3000

Cementing

4000

Drilling Fluids

5000

Wellheads, Packers, Tools and Equipment

6000

Stuck Pipe and Fishing

7000

Well Evaluation

8000

Marine and Miscellaneous

Index Suffixes MST GEN SEM JAK FIX FOR CLY BEA MAG THI MIL DON BRU MAR RAV AME WYF HAR

Master Index and User Guide General Semi-Submersible Drilling Units Jack-Up Drilling Units Fixed Drilling Units Forties Clyde Beatrice Magnus Thistle Miller Don Bruce Marnock Ravenspurn Amethyst Wytch Farm Harding



Section

Description

0000

SAFETY AND ADMINISTRATION

0120/GEN

H2S (Hydrogen Sulphide) Procedures Section A - Wildcat/Exploration Area Section B - Known H2S Areas Appendices

0160/GEN

Use of Explosives in Drilling Operations

0300/GEN

Daily Reports from Rig

0310/GEN

Weekly Reports from Rig

0320/GEN

General Reports from Rig

0400/GEN

Well Control Procedures

0402/GEN

Well Control in High Angle or Horizontal Wells

0403/GEN

Well Control Whilst Logging

0405/GEN

Limited Kick Tolerance

0410/GEN

Shallow Gas Procedures

0413/SEM

Shallow Gas Procedures (Deepwater in DP Mode)

0415/GEN

The Effect of Cold Weather on BOP Stacks and Control Lines

0420/FIX

Surface BOP Testing - General

0420/SEM

Subsea BOP Testing - General

0440/JAK

Pressure Testing 21 ¼” BOP

0441/JAK

Pressure Testing 13 5/8” BOP

UK Operations BP EXPLORATION

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H2S (HYDROGEN SULPHIDE) PROCEDURES

These procedures have been drawn up to ensure that the working environment of the Company’s operations is effectively controlled. This document in no way detracts from the Contractor’s responsibilities in law. It is the responsibility of the Drilling Contractors to produce a written plan describing specific procedures to be followed in the event of an H2S escape for each drilling site. In addition to the procedures identified here, further information and procedures are contained in the BP HSE Practices, Number 10. H2S PROCEDURES INDEX Page INTRODUCTION.

4

SECTION A - WILDCAT/EXPLORATION AREAS.

5

A.1

Equipment.

5

A.1.1

Detection Systems.

5

a) b) c) d) e)

5 6 6 6 6

A.1.2

Fixed Systems. Portable Equipment. Sensor Testing and Calibration. Records. Alternative Detection Methods.

Personal Protection.

7

a) b) c) d) e)

7 7 7 8 8

Type of Equipment. Respiratory Protection. Safe Briefing Area. Additional Equipment. Audible Alarm.

A.2

Emergency Procedures and Contingency Plans.

8

A.2.1 A.2.2 A.2.3 A.2.4

General Procedures. Specific Procedures. Clearance to Safe Conditions. Reporting of H2S Incidence.

8 11 13 13

A.3

Training.

14

A.4

Equipment Checklist.

14


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H2S (HYDROGEN SULPHIDE) PROCEDURES INDEX (cont'd) Page

SECTION B - KNOWN H2S AREAS.

15

B.1

Equipment.

15

B.1.1

Detection Systems.

15

a) b) c) d) e)

15 16 16 16 17

B.1.2

Fixed Systems. Portable H2S Detectors. Sensor Testing and Calibration. Records. Other Detection Systems.

Contracted Safety Equipment and Personnel.

17

a) b) c) d) e) f)

17 17 17 18 19 19

Compressor Unit/Units. Air Storage Cylinders. Self-Contained Compressed Air Breathing Apparatus (CABA). Cascade/Distribution System. Portable H2S Detectors. Personnel.

B.1.3 B.1.4 B.1.5 B.1.6 B.1.7

Required Procedures. Accommodation. Training. General Safety. Communications.

19 20 20 20 21

B.2

Emergency Procedures and Contingency Plans.

21

B.2.1 B.2.2

General Procedures. Specific Procedures.

22 25

B.3

Training.

31

B.4

Equipment Checklist.

31

B.5

Mobile Rig Checklist Guide for Testing H2S Prospects.

31

APPENDIX 1 - Properties of Hydrogen Sulphide.

34

1. 2. 3.

34 35 35

Characteristics. Physiological & Long Term Effects - Table of Concentrations (Table 1). First Aid.

APPENDIX 2 - Drilling Fluid and H2S Control.

37

1. 2. 3.

37 38 39

Principles. Monitoring of H2S in Drilling Fluids. Stocking of Materials.


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H2S (HYDROGEN SULPHIDE) PROCEDURES INDEX (cont'd) Page

APPENDIX 3 - Effects of H2S on Drilling Equipment.

40

1. 2. 3. 4. 5. 6.

40 40 40 40 41 41

Sulphide Stress Cracking (SSC). Factors Affecting Failure. Standards Applying to Metals for H2S Situations. Metals for Use in H2S Environments. Drilling Components for Use in H2S Environments. Precautions Against H2S Corrosion.

APPENDIX 4 - List of Useful Contacts.

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H2S (HYDROGEN SULPHIDE) PROCEDURES INTRODUCTION

Hydrogen Sulphide (H2S) is found in detectable concentrations in oil and gas deposits throughout the World. In the UKCS, there have been relatively small numbers of wells tested which have produced H2S in significant amounts, but reservoirs containing high percentages of H2S have and are being successfully and safely produced in other parts of the World. These are not reasons to show any complacency towards H2S, the effect to both human life and equipment, at even low concentrations, can be devastating. These procedures are designed for normal drilling and testing activities. The document is divided into two major sections which cover the following areas of operations: A. WILDCAT/EXPLORATION AREAS In unexplored areas the occurrence of H2S is a possibility. Similarly in exploration areas, even though nearby wells would seem to indicate that it does not exist. It is expected that all drilling rigs engaged in this area will carry the minimum levels of equipment and follow the procedure in this document. B. KNOWN H2S AREAS Where the occurrence of H2S is considered a distinct possibility, additional safety equipment will be required. This document outlines the extra equipment and stricter procedures that will be necessary. These are additional to the minimum levels of equipment and procedures suggested for exploration areas. There are included a number of Appendices giving background information on the effects of H2S on personnel, drilling muds and drilling equipment.

Note: There is a possibility of H2S occurring during well servicing operations of existing static wells, which formally showed no indication of the gas. Sulphur Reducing Bacteria (SRBs) may be present in the reservoir, or may have been introduced during earlier work. These SRBs can produce H2S from sulphur containing compounds present within the reservoir or formation. Personnel must always be prepared for the presence of H2S during operations on existing wells and follow procedures laid down in Section A, should it be detected.


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H2S (HYDROGEN SULPHIDE) PROCEDURES SECTION A WILDCAT/EXPLORATION AREAS

This section is intended to cover the minimum equipment, training and procedure levels that will be applied to all mobile rigs being used by BP Petroleum Development Limited in the UKCS area. A.1

EQUIPMENT

A.1.1

Detection Systems Both portable H2S gas detectors and a fixed automatic monitoring and alarm system are required, although their accuracy and reliability must first be ascertained particularly in the case of fixed detectors. Flammable gas detection systems that may be installed in these areas should not be considered as being suitable for toxicity monitoring of H2S concentrations. a) Fixed Systems The number and location of sensors should be sufficient to cover expected areas of accumulation and must be tested for their accuracy and reliability. The sensors should be collectively monitored at a central point, in a safe area. For example, the Mud Logging unit or rig control room. The system should be arranged to provide continuous monitoring of those parts of the installation listed below.

Bell Nipple

This is the best location for early warning, but may not be practicable. In this case the sensor should be as close as possible.

Shale Shakers/Header Box Mud Pit Area

Return and suction pits.

Drill Floor

Two sensors.

If possible, the system should have at least two spare channels to allow extra sensors to be fitted as required, e.g. on the trip tank. Additionally and depending on rig design and positioning of living quarters’ air intakes, consideration should be given to installing H2S sensors at the air intakes. Since H2S is heavier than air, sensors must be as close to floor level or mud level as practicable. The system should be set to detect H2S at any individual sensor at 10 ppm. This should sound an alarm and register an alarm at the central monitoring point and at the remote alarm stations. Remote alarms, giving both visual and audible alarm on detection of the preset limit of H2S, should be placed at the following positions: -

Drillers console. Control room. Mud logging unit.


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b) Portable Equipment In addition to the fixed automatic H2S detection system, portable detectors, both electronic and manual, should be available. Portable Continuous Monitor (Electronic) The instrument provided should be continuous and automatic in operation, tamper proof and suitable for use by non-technical personnel. The instrument should give a clear audible and visual alarm in the presence of H2S concentrations at or above 10 ppm. Additionally the unit should be suitable for hazardous areas, of robust construction, easily handled in one man operation, integral power supply and internal function testing. Typical models are: -

Compur 4100. TAC Model 701.

Two detectors should be provided, one in the toolpushers/OIM’s office and one in the control room. H2S Detector Tubes (Manual) H2S detector tubes should meet the current British Standard BS 5343 (1976) Gas Detector Tubes. The detector should be accurate and simple to operate. It should incorporate a hand-operated aspirating pump and colour indication tube graduated directly in ppm H2S. At least one detector set should be provided and normally kept in the contractor toolpusher/OIM’s office. A minimum of 6 tubes are to be kept with the detector at all times. A minimum stock of 50 tubes, range 0 - 60 ppm, of H2S should be maintained on board in a cool place below 68°F. c) Sensor Testing and Calibration (Fixed and Portable) All H2S detection systems and equipment should be tested and calibrated, in accordance with manufacturer’s instruction manuals, on installation and weekly thereafter or as often as necessary depending on the reliability of the detectors. Tests should be a functional simulation to test both accuracy and operational efficiency of the system and equipment. Detector tubes should be checked that they are not out of date, and are suitable for H2S. This will be the responsibility of the OIM. d) Records All testing and calibration results should be recorded. These records should be available for inspection at all times. e) Alternative Detection Methods Smell Sense of smell is not a reliable method of detecting H 2S (see Appendix 1). If any crew member believes that they can smell H2S, they should immediately inform the Contractor toolpusher/OIM. He will then arrange for the area to be investigated using Draeger tubes, or similar devices.


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Mud Analysis By analysis of the drilling mud, either by using a Garrett gas train on routine inspections or a Mud Duck for continuous monitoring, it is possible to determine the level of sulphides in the mud. From this it is possible to infer the amount of H2S in solution in the mud. Variations in the sulphide level will be significant. See also the section on mud systems. A.1.2

Personal Protection The provision of breathing apparatus and its location on the rig is based upon the following premises. Any release of H2S will be detected sufficiently early for BA equipment to be worn. In the event of a substantial release of H2S, the rig will shut down operations and make the well safe. The number of sets is based on the minimum number of personnel to make the well safe. a) Type of Equipment In view of the highly toxic nature of H2S, it is recommended that only BA equipment with a protection rating of 2000, as defined by BS 4275 : 1974, should be used. Such BA equipment should be designed to BS 4667 Part 2 : 1974, or similar standards. b) Respiratory Protection All installations will have at least twelve sets of self-contained BA to the appropriate standard. These sets should have sufficient spare cylinders to allow at least one hour of continuous hard work. This would be two spare bottles for each 1200LBA set, this means a minimum of 36 bottles in total. The sets should be positioned, as far as possible, as follows:

Rig Floor/Doghouse/Derrick 6 sets (Driller, Asst. Driller, 3 x Floormen, Derrickman) Mudroom 1 set (Derrickman/Mud Watcher) Toolpushers Office 3 sets (Toolpusher, BP Representative, Mud Engineer) Control Room 1 set (Spare/Monitor) Mud Logging Unit 1 set (Mud Logger) Consideration should also be given to providing a further six sets, three at each of the outdoor Safe Briefing Areas (see definition below). Additionally, 10 minute escape BA sets should be available in the derrick, mud pit area and depending on risk, the shaker area. BA equipment will be checked regularly in accordance with manufacturer’s recommendations and a record kept of all inspections. This is the responsibility of the OIM. c) Safe Briefing Area In general, it is the responsibility of the OIM to define three safe briefing areas onboard the rig.


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Two of these safe briefing areas will be in the open air on opposite sides of the rig so that at least one will be upwind of any incident. These areas will be used to muster essential personnel. In the event of an incident, a tannoy message will designate which safe briefing area is to be used. In the event that both are unusable, a tannoy message will give the location of an alternative site, e.g. Helideck. The third safe briefing area will be within the accommodation of the rig and will be used to muster all non-essential personnel. It is suggested that the messroom or cinemas would be suitable. d) Additional Equipment Extra wind socks or flags should be provided so that at least one can be seen from all points on the rig. This is to enable personnel to determine the upwind side of the structure to proceed to the correct safe briefing area. Actual location depends on rig design. Retrieval ropes and harnesses need to be available to recover incapacitated personnel. This is normally part of rig equipment. Each rig will have two approved resuscitation units. These, also, are part of the normal rig equipment. e) Audible Alarm Consideration should be given to the use of the drill floor horn or similar type of audible alarm, in preference to the General/Fire Alarm, as a means of alerting on-duty personnel to the impending danger of H2S. A.2

EMERGENCY PROCEDURES AND CONTINGENCY PLANS It is the responsibility of the Drilling Contractor to produce a written plan describing specific procedures to be followed in the event of an H2S escape for each rig. This plan should be discussed and agreed with BP. These plans must be prominently displayed on the rig. The following notes are intended as guidelines for plans of action. These will need to be modified for each individual rig.

A.2.1

General Procedures Condition 1 Normal Operation H2S Less Than 10 ppm in Air at Sensors Well Condition

Normal work, hole open, drilling ahead.

Alarm

None.

Characteristics

Drilling operation under control. This condition will be in effect from surface casing shoe to TD unless it is necessary to go to Condition 2.

General Action

1. Be alert for a condition change. 2. Check and maintain all sensors and safety equipment. 3. Designate three Safe Briefing Areas (SBA) or Muster Points in the event of an incident. Two SBA’s should be in the open air on opposite sides of the rig so that at least one will be upwind of the incident.


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H2S (HYDROGEN SULPHIDE) PROCEDURES 4. Continue training of all personnel on the dangers and reaction to H2S. Carry out training drills, as suggested below, to ensure personnel are familiar with alarms, etc. 5. Though not reliable, smelling H2S may be a first indication and must be reported and investigated. The odour threshold of H2S is very low, i.e. approximately 0.01 ppm. 6. Any occurrence of H2S should be reported on the daily Drill Data report from the Mud Loggers. See also A.2.4 - Reporting of H2S Incidence.

Condition 2 H2S Levels Between 10 ppm and 25 ppm in Air at Sensors Well Condition

Prior to reaching this condition, the hole is open and circulating normally.

Alarm

In mud log unit, drill floor, control room, etc.

Characteristics

Drilling operations under control. H2S concentrations at threshold levels.

General Action

1. Drill floor personnel to don BA sets, but not mask up. Mud Room personnel to don BA sets and mask up. 2. Mud log unit to telephone rig floor, control room, toolpushers/OIM’s office and BP Reps. 3. Shut well in (conforming with standard BOP procedures to make the well safe). 4. Shut down all accommodation ventilation systems. Make general announcement for all non-essential personnel to return to, and remain in, accommodation. 5. Announce which safe briefing area will be used by essential personnel. 6. Increase mud room ventilation to maximum. 7. Switch on degasser, any gas being released in Derrick vent line. 8. Using portable equipment, determine levels of H2S in free air at the drill floor and mud room. 9. Commence circulating treatment mud. Suggested treatments include: a) b) c)

Increasing mud pH. Increasing mud weight. Using scavengers if available.

Normally after a few hours circulation H2S level should decrease to below 10 ppm. In this case continue circulation without choke system until the mud is free of entrained gas. If H2S level does not fall, continue circulation and the BP Rep. will inform the responsible Drilling Superintendent or the duty Drilling Superintendent, outwith office hours. Possible actions by essential personnel: Driller

Will don BA. Raise pipe off bottom to enable use of BOP rams.

Asst. Driller

Will don BA. Stand by on BOP controls, until driller is free to stand by.


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Mud Engineer

Will don BA, mask up and go to mud room. Commence pH and H2S checks. Stand by to start treatment.

Mud Logger

Main operator will don BA and remain in unit. Other personnel will go to accommodation.

Toolpusher

Will don BA and go to drill floor.

BP Representative

Will don BA and go to drill floor.

Derrickman

As soon as practicable, will take BA set from drill floor, don, mask up and report to mud room. Prepare to start treatment.

Floormen

Will don BA and await orders on the rig floor.

OIM/Barge Eng.

Will don BA and go to control room.

Mud Watcher

Will don BA set, mask up and assist with mud treatment.

Radio Operator/ Control Room

Notify standby vessel of situation and to go upwind. Inform incoming helicopters. Make necessary announcements.


Well shut in, circulating through choke system. All essential personnel having donned BA sets. All non-essential personnel in accommodation.

Alarm

As Condition 2.

Characteristics

Drilling operations under control. As Condition 2.

General Action

1. All essential personnel to mask up after tannoy instructions. 2. Control room to instruct all non-essential personnel to go to safe briefing area within the accommodation. 3. Continue circulation of treatment mud.

Specific Action: Barge Engineer/ Crane Operator

Take control at Safe Briefing Area within the accommodation.

Asst. Drill/Rig Crew

Continue with circulation.


Inform standby boat, incoming helicopters if not already informed.

BP Representative

Consult with Duty Drilling Superintendent or Responsible Drilling Superintendent on the situation.


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Condition 4 H2S Levels Greater than 50 ppm Status of Well

Shut in, circulating through choke system. Essential personnel masked up in BA equipment. Non-essential personnel in accommodation Safe Briefing Area.

Alarm

As Condition 2.

Characteristics

Critical well operation, well control problems.

General Actions

1. Shut the well in completely. Monitor drill pipe and annulus pressure. 2. Re-assess the situation. The following points need to be considered: Location of sensor giving high readings. Wind directions/weather conditions. H2S neutraliser availability. Equipment status (BA etc.). Known helicopter movements. Possible evacuation of non-essential personnel. Based on the current situation, a procedure will be agreed to remedy the problem. For example, if wind is adequately dispersing the H2S and sufficient chemicals are available, it may be possible to remove all nonessential personnel, bring in back-up BA equipment and reduce the H2S level by circulation, with increased mud weight.

A.2.2

Specific Procedures H2S Detection While Drilling Proceed as for Conditions 1 to 4. H2S Detection While Tripping Stop tripping and proceed to circulate as per Conditions 1 to 4. Once the level is reduced, go to bottom and complete circulation and condition mud. Consideration may be given to stripping in under special circumstances. Circulating Out Trip Gas Maintain vigilance when trip gas is expected to surface. Have degasser running. In the event of H2S, proceed with Conditions 1 to 4. Circulating Out a Kick Follow normal well kill procedures. If H2S becomes apparent, proceed as per Conditions 1 to 3 and continue to circulate until the kick is out.


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Coring If there is a possibility of H2S being present in a reservoir, and there is a requirement for cores to be taken, the following procedures should be applied to ensure that the core is handled safely. 1. All BA equipment (including cascade lines) to be checked and confirmed operable while running in hole for core run No. 1. 2. FSO to be requested to provide brief summary of H2S effects/precautions at pre-shift safety meetings. 3. Tripping to stop when corebarrel 1000ft below rotary, to allow a Safety meeting to be held, with FSO in attendance. 4. A tannoy announcement must be made, informing all of the imminent core recovery operation, and the associated potential for an H2S gas release. All unauthorised personnel to remain clear of drill floor. 5. Continuous H2S detector to be installed near rotary. 6. FSO to take a gas sample in each box connection when pulling BHA. 7. Once the core barrel is at the table, the rig floor is to be cleared to minimum personnel, with at least two portable H2S detectors. 8. Floormen don BA. Break safety joint and pull back 90ft of inner. Clamp and break same. FSO to sample for H2S. 9. If ANY test result for the presence of H2S is positive, the following actions apply: (a)

All personnel handling or supervising core operations on drillfloor to wear BA until advised by the FSO.

(b)

Core laydown area to be cordoned off. Boxes to be flushed with compressed air by deck operator wearing BA, until FSO confirms that the samples are free of H2S.

(c)

Floormen to be rotated regularly.

10. If all tests are negative, the following actions apply: (a)

Personnel handling core may work without BA, but these sets must be rapidly to hand and in usable condition.

(b)

Samples to be taken by FSO complete with BA when breaking each further inner barrel.

Downhole Samples All downhole samples are to be tested for H2S gas prior to them being removed to the mud logging unit for testing, e.g. Repeat Formation Tester (RFT) samples. Testing It is possible that the first indications of H2S will be during the well testing phase. Well testing will be carried out as normal unless H2S was evident during drilling. However, all test equipment will be H2S proof in wildcat/exploration areas. Separator gas will be routinely checked for H2S. In the event that the concentrations of H2S increase to above 10 ppm in free air or 25 ppm in stream, the test string will be shut in at the manifold and surface equipment flushed through with diesel.


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On condition that the test string can withstand the H2S, the flow will be held closed in. Otherwise the test will be terminated. A report of the conditions will be made to the relevant Drilling Superintendent and the Senior Petroleum Engineer. Consideration will be given to continuing the test if suitable equipment, as shown in Section B, can be mobilised. If it is not possible, consideration will be given to aborting the test until a suitable plan of action can be made.

Note: Acidising limestone may generate H2S until cleaned up. A.2.3

Clearance to Safe Conditions The exact sequence of action to clear an alarm will depend upon the reason for it (e.g. drilling through a sulphurous zone, sampling sour crude, etc.). The general procedure will be: 1. Stop the source of the H2S. 2. Monitor for H2S near the source. Give clearance there when it stays below 10 ppm. 3. Monitor for H2S downwind and downstream of the source. Give clearance in each area when it stays below 10 ppm. Following an H2S incident, all low lying areas of the rig will be inspected by two persons working a buddy system using the portable electronic and/or manual detectors and equipped with BA. Areas inspected should include rig legs, tanks, thruster pods, cellar deck, void spaces, etc.

A.2.4

Reporting of H2S Incidence When H2S is detected in a wildcat/exploration well, and appropriate actions have been taken, a report on the incident must be immediately forwarded to the relevant Drilling Superintendent by the BP Representative. Information sent should include: Hole condition, i.e. drilling, tripping. Depth. Maximum level of H2S encountered in free air. Source of maximum level, i.e. flowline, mud pits. Geological structure being drilled. Action taken. Copies should be sent to the following: 1. 2. 3. 4. 5.

Drilling Superintendent. Senior Drilling Engineer/Office Drilling Engineer. Senior Operations Geologist. Senior Petroleum Engineer. Senior Safety Adviser, Drilling.

This is a reportable incident as per PON 11. A report will be made by BP to the Department of Energy.


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TRAINING All essential personnel, i.e. Contractor drill crews, BP Representative, etc. will be instructed in the use of BA equipment. All supervisory personnel will be instructed on the correct use of the portable H2S gas detectors on the rig. H2S drills should be carried out prior to drilling out of the 13-3/8” and 9-5/8” casing shoes. This will be part of the D5 drill. Information relating to safety measures in the event of H2S should be prominently posted around the rig by the Drilling Contractor. In addition it is strongly recommended, in order to promote efficient safety procedures, that an on-site H2S training programme be established by the Drilling Contractor. As a general outline, the programme should include instruction on the dangers of H2S and Sulphur Dioxide (SO2), the detection systems, alarms, safe briefing areas, actions during Conditions 2 and 3 on H2S alert. Instruction should also be given on rescue and first aid of H2S victims. A list of possible training companies is given in Appendix 4. The OIM is responsible to ensure that training and drills are being satisfactorily carried out. A record will be kept.

A.4

EQUIPMENT CHECKLIST The following is a summary of equipment that will need to be provided under Section A. Responsibility for provision will depend on the rig contract but it is likely to be as shown.

Equipment

Provided By

a) Fixed H2S detector system with 6/7 sensor points and 1 central monitor point and 4 remote alarm points.

Drilling Contractor

b) Two hand portable continuous electronic H2S detectors.

Drilling Contractor

c) One set of H2S detector tubes and pumps, plus 50 tubes of 0 - 60 ppm range.

Drilling Contractor

d) 12 BA sets plus 24 spare bottles of 1200L capacity.

Drilling Contractor

e) 1 x 10 minute escape BA set.

Drilling Contractor

f)

BP

Wind socks (as required) and fluorescent streamers.

g) H2S proof testing gear.

BP

h) 6 hand portable continuous electronic H2S detectors.

BP

i)

BP

1 pallet of zinc carbonate (25 x 25 kg sacks) (see Appendix A2.5).


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H2S (HYDROGEN SULPHIDE) PROCEDURES SECTION B KNOWN H2S AREAS

This section applies to work within known H2S quadrants. For known quadrants at present with concentrations above 50 ppm. In writing these guidelines, it is assumed that H2S will occur in the target or reservoir zone. This may not be the case and each well should be individually planned. The general philosophy for drilling in known H2S areas is that the basic conditions of Section A will be followed until some point prior to entering the H2S section, say 9–5/8” casing shoe. After that point these extra regulations will apply. The extra equipment etc. will be supplied by BP for known H2S quadrants. B.1

EQUIPMENT

B.1.1

Detection Systems Both portable H2S gas detectors and a fixed automatic monitoring and alarm system are required and must be tested for their accuracy and reliability. Flammable gas detection systems that may be installed in these areas should not be considered as being suitable for toxicity monitoring of H2S concentrations. a) Fixed Systems The number and location of sensors should be sufficient to cover expected areas of accumulation. The sensors should be collectively monitored at a central point, in a safe area. For example, the Mud Logging unit or rig control room.

If sensors cannot be collectively monitored at a central point, reporting procedure must be in place to ensure immediate and effective communication to control area. The system should be arranged to provide continuous monitoring of those parts of the installation listed below.

Bell Nipple



Above all active pits.

Drill Floor

Minimum of two sensors, one in vicinity of dog-house.

Mud Pumproom

Minimum of one sensor.

Accommodation

One sensor at each main ventilation intake. It should be proved that the fans do trip on monitoring any concentrations of H2S or gas.

Well Test Area

Where possible in vicinity of separator and sampling point.

BA Compressor

At air intakes for main cascade system compressor. If two air intakes are required, both should be fitted with sensors and proved to trip compressor on detection of H2S.


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Trip Tank

Consideration to be given to the monitoring of H2S when the trip tank is exposed to the well.

Spare detector heads should be onboard to enable replacement of defective units. Since H2S is heavier than air, sensors must be as close to floor level or mud level as practicable. The system should be set to detect H2S at any individual sensor at 10 ppm. This should sound and register an alarm at the central monitoring point and at the remote alarm stations. Remote alarms, giving both visual and audible alarms on detection of the preset limit of H2S, should be at the following positions as a minimum requirement: - Drillers console. - Control room. - Mud logging unit. b) Portable H2S Detectors In addition to the fixed H2S detection system, portable detectors, both electronic and manual, must be available and must be tested for their accuracy and reliability. Portable Continuous Monitors (Electronic) The instrument provided should be continuous and automatic in operation, tamper proof and suitable for use by non-technical personnel. The instrument should give a clear audible and visual alarm in the presence of H2S concentrations at or above 10 ppm. Additionally the unit should be suitable for hazardous areas, of robust construction, easily handled in one man operation, integral power supply and internal function testing. H2S Detector Tubes (Manual) H2S detector tubes should meet the current British Standard BS 5343 (1976) Gas Detector Tubes. The detector should be accurate and simple to operate. It should incorporate a hand-operated aspirating pump and colour indication tube graduated directly in ppm H2S. At least two detector sets should be provided and normally kept in the Control Room and BP Rep’s office. A minimum of 6 tubes are to be kept with each detector at all times. A minimum stock of 50 tubes, range 0 - 60 ppm, of H2S should be maintained on board in a cool place below 68°F. c) Sensor Testing and Calibration (Fixed and Portable) All H2S detection systems and equipment should be tested and calibrated, in accordance with manufacturer’s instruction manuals, on a weekly basis or as often as necessary depending on the reliability of the detectors. Tests should be a functional simulation to test both accuracy and operational efficiency of the system and equipment. Detector tubes should be checked that they are not out of date, and are suitable for H2S. This is the responsibility of the OIM. d) Records All testing and calibration results should be recorded. These records should be available for inspection at all times.


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e) Other Detection Systems (Fixed and Portable) The fixed flammable gas detection system, as installed, should be calibrated, tested and fully operational. It is recommended that sensors should also be calibrated and cover the same general areas as for fixed H2S sensors. There should be 4 portable meters onboard, two for measuring oxygen and two for measuring flammable concentrations of gas. This is a legal requirement. CAUTION: Sense of smell is not a reliable method of detecting H2S. If any crew member believes that they can smell H2S, they should immediately inform the Contractor toolpusher/OIM. He will then arrange for the area to be investigated using Draeger tubes, or similar devices. B.1.2

Contracted Safety Equipment and Personnel Dependent on hazard expected or perceived, the following equipment should be considered to reduce potential risk to onboard personnel during well test periods. a) Compressor Unit/Units Suitable compressor unit producing breathing air to, or exceeding, BS 4275. Two air intakes for supply air to compressor unit, situated at opposite sides of the rig. b) Air Storage Cylinders To BS 5045 or equivalent, sufficient quantity to provide 140 manhours of compressed air to the cascade/distribution system. c) Self-Contained Compressed Air Breathing Apparatus (CABA) Above to include the following: i)

Sufficient 30 minute CABA suitable for inter connection to air line cascade system c/w one spare cylinder for each set.

ii)

Sufficient 10 minute hip set suitable for inter connection to air line cascade system.

iii)

Sufficient 10 minute escape sets for evacuation only.

Suggested distribution of apparatus is as follows: For Controlled Situation When Gas is Expected Essential Personnel : Rig Floor Derrickman (1) Drill Crew (6) Toolpusher Subsea Eng. BP Rep. Drilling Eng. Pet.Eng./Geologist Contract Service Personnel Well Test Personnel

Monkey Board - use escape set Drill Floor - use air outlets Use 30 min. set from Drilling Office Use 30 min. set from Drilling Office Use 30 min. set from Company Office Use 30 min. set from Company Office Use 30 min. set from Company Office Use 30 min. set from Contractors Unit Use air outlets


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H2S (HYDROGEN SULPHIDE) PROCEDURES SECTION B KNOWN H2S AREAS

This section applies to work within known H2S quadrants. For known quadrants at present with concentrations above 50 ppm. In writing these guidelines, it is assumed that H2S will occur in the target or reservoir zone. This may not be the case and each well should be individually planned. The general philosophy for drilling in known H2S areas is that the basic conditions of Section A will be followed until some point prior to entering the H2S section, say 9–5/8” casing shoe. After that point these extra regulations will apply. The extra equipment etc. will be supplied by BP for known H2S quadrants. B.1

EQUIPMENT

B.1.1

Detection Systems Both portable H2S gas detectors and a fixed automatic monitoring and alarm system are required and must be tested for their accuracy and reliability. Flammable gas detection systems that may be installed in these areas should not be considered as being suitable for toxicity monitoring of H2S concentrations. a) Fixed Systems The number and location of sensors should be sufficient to cover expected areas of accumulation. The sensors should be collectively monitored at a central point, in a safe area. For example, the Mud Logging unit or rig control room.

If sensors cannot be collectively monitored at a central point, reporting procedure must be in place to ensure immediate and effective communication to control area. The system should be arranged to provide continuous monitoring of those parts of the installation listed below.

Bell Nipple



Above all active pits.

Drill Floor

Minimum of two sensors, one in vicinity of dog-house.

Mud Pumproom

Minimum of one sensor.

Accommodation

One sensor at each main ventilation intake. It should be proved that the fans do trip on monitoring any concentrations of H2S or gas.

Well Test Area

Where possible in vicinity of separator and sampling point.

BA Compressor

At air intakes for main cascade system compressor. If two air intakes are required, both should be fitted with sensors and proved to trip compressor on detection of H2S.


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Trip Tank

Consideration to be given to the monitoring of H2S when the trip tank is exposed to the well.

Spare detector heads should be onboard to enable replacement of defective units. Since H2S is heavier than air, sensors must be as close to floor level or mud level as practicable. The system should be set to detect H2S at any individual sensor at 10 ppm. This should sound and register an alarm at the central monitoring point and at the remote alarm stations. Remote alarms, giving both visual and audible alarms on detection of the preset limit of H2S, should be at the following positions as a minimum requirement: - Drillers console. - Control room. - Mud logging unit. b) Portable H2S Detectors In addition to the fixed H2S detection system, portable detectors, both electronic and manual, must be available and must be tested for their accuracy and reliability. Portable Continuous Monitors (Electronic) The instrument provided should be continuous and automatic in operation, tamper proof and suitable for use by non-technical personnel. The instrument should give a clear audible and visual alarm in the presence of H2S concentrations at or above 10 ppm. Additionally the unit should be suitable for hazardous areas, of robust construction, easily handled in one man operation, integral power supply and internal function testing. H2S Detector Tubes (Manual) H2S detector tubes should meet the current British Standard BS 5343 (1976) Gas Detector Tubes. The detector should be accurate and simple to operate. It should incorporate a hand-operated aspirating pump and colour indication tube graduated directly in ppm H2S. At least two detector sets should be provided and normally kept in the Control Room and BP Rep’s office. A minimum of 6 tubes are to be kept with each detector at all times. A minimum stock of 50 tubes, range 0 - 60 ppm, of H2S should be maintained on board in a cool place below 68°F. c) Sensor Testing and Calibration (Fixed and Portable) All H2S detection systems and equipment should be tested and calibrated, in accordance with manufacturer’s instruction manuals, on a weekly basis or as often as necessary depending on the reliability of the detectors. Tests should be a functional simulation to test both accuracy and operational efficiency of the system and equipment. Detector tubes should be checked that they are not out of date, and are suitable for H2S. This is the responsibility of the OIM. d) Records All testing and calibration results should be recorded. These records should be available for inspection at all times.


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e) Other Detection Systems (Fixed and Portable) The fixed flammable gas detection system, as installed, should be calibrated, tested and fully operational. It is recommended that sensors should also be calibrated and cover the same general areas as for fixed H2S sensors. There should be 4 portable meters onboard, two for measuring oxygen and two for measuring flammable concentrations of gas. This is a legal requirement. CAUTION: Sense of smell is not a reliable method of detecting H2S. If any crew member believes that they can smell H2S, they should immediately inform the Contractor toolpusher/OIM. He will then arrange for the area to be investigated using Draeger tubes, or similar devices. B.1.2

Contracted Safety Equipment and Personnel Dependent on hazard expected or perceived, the following equipment should be considered to reduce potential risk to onboard personnel during well test periods. a) Compressor Unit/Units Suitable compressor unit producing breathing air to, or exceeding, BS 4275. Two air intakes for supply air to compressor unit, situated at opposite sides of the rig. b) Air Storage Cylinders To BS 5045 or equivalent, sufficient quantity to provide 140 manhours of compressed air to the cascade/distribution system. c) Self-Contained Compressed Air Breathing Apparatus (CABA) Above to include the following: i)

Sufficient 30 minute CABA suitable for inter connection to air line cascade system c/w one spare cylinder for each set.

ii)

Sufficient 10 minute hip set suitable for inter connection to air line cascade system.

iii)

Sufficient 10 minute escape sets for evacuation only.

Suggested distribution of apparatus is as follows: For Controlled Situation When Gas is Expected Essential Personnel : Rig Floor Derrickman (1) Drill Crew (6) Toolpusher Subsea Eng. BP Rep. Drilling Eng. Pet.Eng./Geologist Contract Service Personnel Well Test Personnel

Monkey Board - use escape set Drill Floor - use air outlets Use 30 min. set from Drilling Office Use 30 min. set from Drilling Office Use 30 min. set from Company Office Use 30 min. set from Company Office Use 30 min. set from Company Office Use 30 min. set from Contractors Unit Use air outlets


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Essential Personnel Other Than Rig Floor OIM CRO Mate Elec. Eng. Chief Eng. 2 Mech. Techs. on duty 3/4 Schlumberger Medic Well Logger Mud Eng./Loss Control Eng. Cementer Safety Reps. Radio Officer

Use 30 min. set from Control Room Use 30 min. set from Control Room Use 30 min. set from Control Room Use 30 min. set from Control Room Use 30 min. set from Maint. Office Use 30 min. set from Workshop Use 30 min. set from Contractors Unit Use 30 min. set from Rig Office Use 30 min. set from Logging Unit Use 30 min. set from Mud Lab Use 30 min. set from Cement Room Use 30 min. set from Unit Use 30 min. set from Radio Room

All personnel not mentioned above to remain inside accommodation or as instructed by the OIM. Guidelines for BA Set Distribution P 1200 (30 min) Monkey Board Drill Floor Drilling Office Company Office Control Room Mud Pit Area Mud Pump Room Sack Room Cement Room Logging Unit Mud Lab Radio Room Medic Maintenance Office Mech. Workshop Port Crane Starboard Crane Elec. Workshop Subsea Workshop Welders Shop Main Stores Cinema Well Test Unit EM Generator Room (for storage) TOTAL On Board

Escape Sets (10 min)

HIP (10 min) 1 8

2 3 4

4 2 2 2 2

1 2 1 1 1 2

1 12

30

3

2 2 4 2 2 2 50 9 20 100

1 2

20

Above equipment is in addition to statutory rig equipment regards BA sets and compressors. d) Cascade/Distribution System To provide sufficient outlets as required to allow persons to work connected to the system. All outlets to meet BS 4275 or equivalent.


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e) Portable H2S Detectors As for portable continuous monitors (Electronic) in Section B.1.1 (b). All portable electrical equipment to be to British Approvals Service for Elec. Equipment in Flammable Atmospheres, BASEEFA or equivalent intrinsically safe specification. f)

Personnel i)

Minimum of two service company personnel should be present when testing wells with high concentrations of H2S. Prior to mobilising personnel, the service company should be supplied with sufficient information to allow them to tailor a package specifically for that test. Information to be supplied would include expected H2S level, number and duration of flow periods.

ii)

Duties As required by OIM/BP Rep. to monitor H2S and advise. Through consultation with OIM/BP Rep., provide information and assist training of all staff, e.g: a) Proficient use of all contractor CABA equipment and portable gas detectors. b) Hazards and properties of H2S. c) Actions to take in H2S situations. d) Carry out and assist rescue training in H2S atmospheres. e) Patrol areas around rig, monitoring for H2S accumulations.

iii) B.1.3

Ensure full operational status of equipment and report any deficiencies/defects immediately to OIM/BP Rep.

Required Procedures a) For any well test accidents/incidents, ensure correct reporting procedures are carried out as follows: i)

Well Control and H2S Incident a) Telex as per Reporting Procedures Section of the Guidelines for Drilling Operations. b) BP accident/incident report form. c) PON 11. d) OIR 9a if applicable (see form for requirements).

ii)

Hydrocarbon Spillage (if applicable) a) Telex as per Reporting Procedures Section of the Guidelines for Drilling Operations. b) BP accident/incident report form. c) PON 1. d) OIR 9a if applicable (see form for requirements).


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iii)

Hazardous Areas To ensure all doorways, openings, etc. for designated hazardous areas are kept closed at all times except for access and that vent intake/extraction fans to these spaces fully operational and effective. Entry into spaces below main deck level, i.e. column spaces, propulsion rooms, warehouse, store rooms, etc., should be restricted and access doors kept closed/sealed. If circumstances dictate, entry into these spaces should be sanctioned by OIM/Area Authority only and an entry permit made out.

ALL EXTERNAL DOORS TO BE KEPT SHUT EXCEPT FOR ACCESS. iv)

Permits During well testing phase, hot work permits should only be issued by OIM/Area Authority following consultation with the BP Rep. or his designate.

B.1.4

Accommodation Ensure all windows, doors and non-essential intakes are closed if not in use. Personnel movements to be closely monitored and controlled. Recommend a man be at each exit to police restrictions.

B.1.5

Training a) All rig personnel to be trained in the use of 30 minute CABA and 10 minute escape sets. All essential personnel, i.e. drill crews, BP Representative, etc. to be fully trained in the use of all BA equipment including hip sets and cascade system. b) Ensure, through lectures, all staff understand the hazardous nature and rescue procedures regarding H2S. Particular attention to rescue training should be given to drill crews, fire teams, medic and first aid parties. Medic should be given specific information to assist in treating H2S affected personnel. c) To carry out regular H2S drills, mustering at designated safe briefing areas. It is recommended that the signal/alarm initiating such drills should differ from other emergency alarms. On sounding of alarm, an announcement will follow on PA giving safe muster areas and any other relevant information.

B.1.6

General Safety a) As required, ensure standby vessel and any other attendant craft remain upwind during risk periods when testing. b) Full consideration given to possible restrictions in helicopter movements. Ensure interested parties informed. c) Reduce overall manning levels to operational minimum.


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d) Ensure clean shaven policy is enforced; only facial hair which could interfere with the seal of the BA mask need be removed. e) High visibility streamers and wind socks to be prominently positioned throughout rig to ascertain accurate wind direction. f)

Ensure sick bay provided with stimulant drugs, i.e. Adrenalin and Amyl Nitrate for use with H2S affected personnel. These drugs are normally held onboard as part of the rig’s inventory.

B.1.7

Communications All internal and external communication and PA systems should be fully operational prior to testing. Systems to include: a) Internal and external PA system. b) Full radio room transmitter and receiver systems including Marisat phone and telex links. c) Internal telephone system. d) All talk-back systems as fitted. e) Portable and fixed VHF radios including crane sets. f)

Portable and fixed UHF radios. During testing phase extra sets may be required to ensure adequate on-site communications.

N.B. Ensure compatible frequencies if utilised together with rig sets. Due to communication difficulties if wearing BA sets, chalk boards could be considered. B.2

EMERGENCY PROCEDURES AND CONTINGENCY PLANS It is the responsibility of the Drilling Contractor to produce a written plan describing specific procedures to be followed in the event of an H2S escape for each rig. This plan should be discussed and agreed with BP. These plans must be prominently displayed on the rig. The following notes are intended as guidelines for plans of action. These will need to be modified for each individual rig. To avoid incidents it is essential that drilling operations, in areas likely to produce H2S, are thoroughly planned and all eventualities are covered as far as is reasonably practicable. The following is a list of points which should be considered: 1. Early contact should be made with the Drilling Contractors to inform them of the likelihood of H2S. 2. Early contact with Service Companies so that they can arrange for suitable equipment and personnel. 3. The presence of H2S will affect the selection of mud system to be used on the well.


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4. The presence of H2S may affect casing design. 5. The well control system may be similarly affected. 6. Rig well testing lines may need to be altered. The above list is not exclusive to other points which may require consideration. B.2.1

General Procedures Condition 1 Normal Operation H2S Levels Less Than 10 ppm in Air at Sensors Well Condition

Normal work, hole open, drilling ahead.

Alarm

None.

Characteristics

Drilling operation under control. This condition will be in effect from surface casing shoe to TD unless it is necessary to go to Condition 2.

General Action

1. Be alert for a condition change. 2. Check and maintain all sensors and safety equipment. 3. Designate three (3) Safe Briefing Areas (SBA) or Muster Points in the event of an incident. Two of the SBA’s should be in the open air on opposite sides of the rig so that at least one will be upwind of the incident. 4. Continue training of all personnel on the dangers and reaction to H2S. Carry out training drills, as suggested below, to ensure personnel are familiar with alarms, etc. 5. Though not reliable, smelling H2S may be a first indication and must be reported and investigated. 6. Any occurrence of H2S should be reported on the daily Drill Data report from the Mud Loggers. See also A.2.4 - Reporting of H2S Incidence.


Hole open, circulating normally prior to reaching this condition.

Alarm


Characteristics

Drilling operations under control. H2S concentrations at threshold levels.

General Action

1. Drill floor and mud room personnel to don BA sets and mask up. 2. Mud log unit to telephone rig floor, control room, toolpushers/OIM’s office and BP Representative. 3. Switch on degasser, any gas being released in Derrick vent line.


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H2S (HYDROGEN SULPHIDE) PROCEDURES 4. Announce which Safe Briefing Area (SBA) will be used by essential personnel: a) Shut well in (conforming with standard BOP procedures to make the well safe). b) Shut down all accommodation ventilation systems. Make general announcement for all non-essential personnel to return to, and remain in, accommodation until advised by OIM on course of action to be taken. 5. Using portable equipment, determine levels of H2S in free air at the following areas: a) b) c) d)

Drill Floor. Mud Room. Shaker Screen Area. All Drilling Areas.

Report back to Installation Manager. 6. Increase mud room ventilation to maximum. 7. Commence circulating and treat mud. Suggested treatments include: a) Increasing mud pH. b) Increasing mud weight. c) Using available scavengers. Normally after a few hours circulation H2S level should decrease to below 10 ppm. In this case continue circulation without choke system until the mud is free of entrained gas. If H2S level does not fall, continue circulation and the BP Representative will inform the responsible Drilling Superintendent or the duty Drilling Superintendent, outwith office hours. Possible actions by essential personnel: Driller

Will don BA and mask up. Raise pipe off bottom to enable use of BOP rams.

Asst. Driller

Will don BA and mask up. Stand by on BOP controls, until driller is free to stand by.

Mud Engineer

Will don BA and mask up. Commence pH and H2S checks. Stand by to start treatment.

Mud Logger

Main operator will don BA and remain in unit. Other personnel will go to accommodation.

Toolpusher

Will don BA and mask up. Report to drill floor.

BP Representative

Will don BA and mask up. Report to drill floor.

Derrickman

As soon as practicable, will take BA set from drill floor, don set and mask up. Report to mud room. Prepare to start treatment.

Floormen

Will don BA and mask up. Await orders on the rig floor.

OIM/Barge Eng.

Will don BA and go to control room.


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Mud Watcher Radio Operator/ Control Room

Will don BA and mask up. Assist with mud treatment. Notify standby vessel of situation and to go upwind. Inform incoming helicopters to stay clear. Make necessary announcements.


Well shut in, circulating through the choke system. All essential personnel to have donned BA sets. Non-essential personnel in accommodation. Personnel in pump room area to be masked up.

Alarm

General audible alarm.

Characteristics

Drilling operations under control. As Condition 2.

General Actions

1. All essential personnel to be masked up. 2. Control room to instruct all non-essential personnel to go to Safe Briefing Area (SBA) within the accommodation. 3. Continue circulation of treated mud.

Specific Actions: Barge Engineer/ Crane Operator

Take control at Safe Briefing Area (SBA) within the accommodation.

Asst. Drill/Rig Crew

Continue with circulation.


Inform standby boat, incoming helicopters if not already informed.

BP Representative

Consult with Duty Drilling Superintendent or Responsible Drilling Superintendent on the situation.

Condition 4 H2S Levels Greater than 50 ppm in Air at Sensors Status of Well

Shut in, circulating through choke system. Essential personnel masked up in BA equipment. Non-essential personnel in accommodation Safe Briefing Area.

Alarm

As Condition 2.

Characteristics

Critical well operation, well control problems.

General Actions

1. Shut the well in completely. Monitor drill pipe and annulus pressure. 2. Re-assess the situation. The following points need to be considered: Location of sensor giving high readings. Wind directions/weather conditions. H2S neutraliser availability. Equipment status (BA etc.).


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H2S (HYDROGEN SULPHIDE) PROCEDURES Known helicopter movements. Possible evacuation of non-essential personnel. Based on the current situation, a procedure will be agreed to remedy the problem. For example, if wind is adequately dispersing the H2S and sufficient chemicals are available, it may be possible to remove all nonessential personnel, bring in back-up BA equipment and reduce the H2S level by circulation.

B.2.2

Specific Procedures (in H2S Zone) At all times when BA equipment is required, it is recommended that the air line manifold system be utilised in preference to self-contained breathing apparatus. 1. Drilling Proceed as for Conditions 1 to 4. 2. Circulating Out Trip Gas All drilling and mud room personnel will be masked up. BA equipment tied into the manifold system will be worn 30 minutes prior to bottoms up, by all rig floor personnel and mud room personnel. The degasser will be started at this time. Mud loggers will inform toolpusher when trip gas is up and H2S level is below 10 ppm. Using portable equipment, determine level of H2S in drilling areas. A tannoy message will warn all non-essential personnel to stay away from the drill floor and mud tank areas. 3. Circulating Out a Kick Follow normal well kill procedures. If H2S becomes apparent, proceed as per Conditions 1 to 3 and continue to circulate until the kick is out. BA will be worn 30 minutes prior to the influx coming to surface. 4. While Tripping Prior to POH circulate the mud system. Treat to achieve pH 10.5 to 11 and check that soluble sulphides level is not rising. If H2S is detected whilst tripping, then proceed as for Conditions 1 to 4, circulate at present position then run to bottom to circulate all the well. Consideration may be given to stripping in under special circumstances. 5. Coring If there is a possibility of H2S being present in a reservoir, and there is a requirement for cores to be taken, the following procedures should be applied to ensure that the core is handled safely. 1.

All BA equipment (including cascade lines) to be checked and confirmed operable while running in hole for core run No. 1.

2.

FSO to be requested to provide brief summary of H2S effects/precautions at pre-shift safety meetings.

3.

Tripping to stop when corebarrel 1000ft below rotary, to allow a Safety meeting to be held, with FSO in attendance.


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4.

A tannoy announcement must be made, informing all of the imminent core recovery operation, and the associated potential for an H2S gas release. All unauthorised personnel to remain clear of drill floor.

5.

Continuous H2S detector to be installed near rotary.

6.

FSO to take a gas sample in each box connection when pulling BHA.

7.

Once the core barrel is at the table, the rig floor is to be cleared to minimum personnel, with at least two portable H2S detectors.

8.

Floormen don BA. Break safety joint and pull back 90ft of inner. Clamp and break same. FSO to sample for H2S.

9.

If ANY test result for the presence of H2S is positive, the following actions apply: (a) All personnel handling or supervising core operations on drillfloor to wear BA until advised by the FSO. (b) Core laydown area to be cordoned off. Boxes to be flushed with compressed air by deck operator wearing BA, until FSO confirms that the samples are free of H2S. (c)

10.

Floormen to be rotated regularly.

If all tests are negative, the following actions apply: (a)

Personnel handling core may work without BA, but these sets must be rapidly to hand and in usable condition.

(b)

Samples to be taken by FSO complete with BA when breaking each further inner barrel.

Display warning signs where core is being handled or stored. Cores not to be stored in enclosed spaces where H2S concentrations may build up. 6. Open Hole Logging Inform logging company, in advance, that H2S is present or is likely to be present. When POH, wash tool and cable with scavenger and spray with inhibitor. When recovering and handling RFT samples chamber personnel will have donned BA and masked up, until chamber has been vented and purged. 7. Testing This phase of the drilling operation will be the first time at which H2S is produced to surface. Consequently, the risk factor is higher. To cope with this eventuality, the following precautions should be taken: a)

All service companies involved in testing to be informed in advance that H2S is present.

b)

All testing equipment shall be approved for H2S duty.

c)

Unless otherwise stated below, all normal testing procedures will be observed, i.e. first opening of tools will be in daylight, etc.


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H2S (HYDROGEN SULPHIDE) PROCEDURES On initial opening of the tool string, BA equipment and masks will be worn by all rig floor and testing personnel. These will continue to be worn until the level of H2S in free air has been established either at the choke or at the separator. Depending on the level (Long Term Exposure Limit (LTEL)), personnel will be allowed to demask in accordance with testing conditions. In stream H2S will be monitored every 10 minutes for a change in level. Once level has stabilised, sampling rate should be reduced at the discretion of the BP Representative/PE.

e)

DUAL positive ignition sources will be provided for both oil and gas burners. Flare gun will be used to light burners if ignition system fails (ensure gas bottles are full). Diesel burning pilot flames should be used when testing heavy crude oils.

f)

The Testing Period referred to in this section is defined as the whole time from the test tools being first opened until the test tools are recovered to surface.

g)

All non-essential personnel shall be restricted to the accommodation area during the Testing Period. The control of all personnel movements is the responsibility of the OIM, who will consult with the BP Representative.

h)

BA will be worn by all personnel outside of the accommodation during the Testing Period. The requirements to mask up will be notified by tannoy message as circumstances dictate.

i)

No open tanks will be used for collecting flow products. Surge tanks and separators will be equipped with overboard vent lines from the relief valve and rupture disc to below the lowest rig deck. Venting of gas during shrinkage measurements, sampling and gas orifice changes should be done through bleed-off lines run to a safe venting area. All pneumatic separator valve controls must be supplied with rig air (i.e. separator gas must not be used).

j)

Testing personnel will mask up prior to operating valves or opening equipment that has contained H2S. For example, changing chokes, operating flowhead valves, using bubble hoses, taking separator samples, etc.

k)

There will probably be a background level of H2S during testing which can come from a variety of sources (incomplete combustion at the flare, weeping valves, flanges, chiksans, etc.). The important thing is to be aware of any increases in this background level and to take appropriate action. The installation will also be monitored for SO2 (a product of combustion and more toxic than H2S) using hand-operated monitors (Draeger tubes).

l)

At the end of the test, reverse circulate tubing contents to flare. Circulate conventionally until satisfied that mud sulphide level is stable and pH is 10.5 to 11.

m)

Prior to POH, slug tubing with inhibitor.

n)

5 stands before the first test-tool gets to surface, i.e. reverse circulating valve, all rig floor personnel will mask up with BA sets. BA will continue to be worn until the test string has been broken down, sample chambers have been vented and purged and slip joints stroked. When deciding the specific actions to be taken in the event of certain levels of H2S, it must be remembered that both the concentration of H2S in air at the sensors and the concentration of H2S in stream must be considered.


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H2S (HYDROGEN SULPHIDE) PROCEDURES Whichever condition has the more stringent precautions will be the one followed.

Note: There is an increased likelihood of hydrates in the presence of H2S. H2S in Stream There are 4 alert conditions for in-stream concentrations: 1. 20 - 100 ppm

(because sense of smell is lost at approximately 100 ppm).

2. 100 - 250 ppm

(because permanent damage can result from exposure at 250 ppm).

3. 250 - 700 ppm

(because 700 ppm is fatal within 2 - 3 minutes).

4. 700 + ppm

(for planned high H2S well testing).

1. 20 - 100 ppm

a) Personnel who were masked at initial opening may now demask if the instream rate is established at below 100 ppm. Tannoy instructions will be made. Exceptions are personnel operating valves, sampling, etc. b) Flow periods may continue into the night. c) The test string may be re-opened at night provided that nothing has been changed in the surface equipment layout, e.g. no lines have been broken. d) Test duration should be a minimum.

2. 100 - 250 ppm

a) Personnel in the test area and rig floor will mask up. Tannoy instructions will be made. b) Flow periods may continue into the night. c) Continual monitoring of all test and drilling areas.

3. 250 - 700 ppm

a) All personnel outside accommodation will be masked up. Tannoy instructions will be made. b) Flow period may continue into the night. c) No opening or re-opening at night.

4. Over 700 ppm

a) All personnel outside of the accommodation area will mask up. Tannoy instructions will be made. b) Report the test data to the responsible Drilling Superintendent. c) Due to much increased SO2 production during flaring, increased numbers of SO2 detectors are to be fitted by the flare booms. d) All H2S, Hydrocarbon Gas and SO2 detectors to be tested and calibrated prior to test.


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H2S (HYDROGEN SULPHIDE) PROCEDURES e) Commencement of well test to be during daylight hours only. Flow may continue into the night but no re-opening of the well may be conducted during the hours of darkness. f)

Windspeed must be a minimum of 5 knots in such a direction to take any escaped gases away from accommodation modules. A light windsock to monitor wind direction is to be fitted.

g) Rig personnel to be kept to an absolute minimum during the test period. All persons involved must be monitored in and out of the accommodation. h) All ventilation and access to pontoons and internal workspaces to be closed. All personnel requiring access to these areas during well test periods must first obtain an entry permit - remember H2S is heavier than air and will accumulate in low spaces. Testing Condition I H2S Levels Less Than 10 ppm in Air at Sensors Alarm

None.

Characteristics

Testing operation under control.

General Actions

1. Be alert for a condition change. 2. Check and maintain all sensors and safety equipment. 3. Check all well testing equipment for leaks. 4. Though not reliable, smelling H2S may be a first indication and must be reported and investigated. 5. Non-essential personnel restricted to accommodation. 6. Personnel outside accommodation, who will have donned BA, need not be masked up if H2S in stream stabilised and is below 100 ppm. Over 100 ppm in stream, they must mask up. A tannoy message will be made in either event. Exceptions are personnel operating valves, etc. who must wear a mask (see (j) above).

Testing Condition II H2S Levels Between 10 ppm and 25 ppm in Air at Sensors Alarm


Characteristics

Testing operation under control. H 2 S concentration above long term exposure limit of 10 ppm.

General Actions

1. Mud log unit/control room to telephone rig floor, toolpusher/OIM’s office, BP Representative and control room/mud log unit. 2. Continue with test. Isolate source of H2S. 3. Shut down accommodation ventilation systems.


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H2S (HYDROGEN SULPHIDE) PROCEDURES 4. Make general accouncement for all non-essential personnel to remain in the accommodation. 5. Announce which safe briefing area will be used by essential personnel. 6. All personnel outside the accommodation to mask up.

Specific Actions Chief Well Tester/ Toolpusher/ BP Representative

Will don BA sets, mask up and, using a buddy system, investigate the source of H2S using suitable hand-portable equipment.

Radio Operator/ Con trol Room Op.

Notify standby vessel of situation and to take up a position upwind of rig. Inform any incoming helicopters to stay clear until situation improves.

Testing Condition III H2S Levels Between 25 ppm and 50 ppm in Air at Sensors Alarm

As Condition II.

Characteristics

Testing operations under control. H2S concentration above long term exposure limit of 10 ppm.

General Actions

1. Instruct non-essential personnel to go to Safe Briefing Area in the accommodation. 2. Terminate the test if the source of H2S cannot be isolated. If the source is due to incomplete combustion at the flare, cut back the choke size.

Specific Actions Chief Well Tester/ Toolpusher

Continue investigation of source of H2S and isolate if possible.

BP Representative

Inform relevant DS of situation.

Radio Operator

Notify standby vessel and helicopters if not already done. Standby to make announcements.

OIM/Barge Eng.

Take control of accommodation Safe Briefing Area.

Testing Condition IV H2S Levels Greater Than 50 ppm in Air at Sensors Alarm

As Condition 2.

Characteristics

Testing operation control problems.

General Actions

1. Terminate test. 2. Shut well in.

Specific Actions

BP Representative to inform relevant DS of situation.


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TRAINING As suggested in Section A, it is expected that the Drilling Contractor will already be providing a training programme for his employees. When in a known H2S area and while additional regulations are in force, BP will provide qualified personnel to instruct on the use of BA and on the dangers of H2S.

B.4

EQUIPMENT CHECKLIST The following is a summary of equipment that should be provided under Section B. The responsibility for provision of equipment will depend upon the particular rig contract, but is likely to be as shown below.

B.5

Equipment

Provided By

Additional fixed detectors into existing system (as required).

BP/Drilling Contractor

10 personal alarms.

BP

LP compressor for 12 man service and 1 hour reserve capability.

BP

20 outlets on manifold system.

BP

12 off escape BA sets for manifold system.

BP

30 BA sets plus 60 spare bottles of 1200L capacity. These are excluding the rig’s own sets.

BP

HP Compressor.

BP

(100 Elsa), 10 minute escape sets.

BP

Scavenger/neutraliser (0.5 lb/bbl for the full circulating system plus kick control).

BP

Test equipment for H2S work.

BP

Qualified personnel.

BP

Mud Duck.

BP

MOBILE RIG CHECKLIST GUIDE FOR TESTING H2S PROSPECTS Requirements 1.

Ensure all portable O2 (oxygen) meters fully operational and recalibrated.

2.

Ensure all H2S gas detector heads operational and recalibrated. This to include portable units (electronic and manual).

3.

ALL personnel trained in use of CABA and escape sets.

4.

Unique alarm for H2S emergency.

5.

Standby vessel to be positioned upwind during testing.


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6.

Reduce overall manning levels to operational minimum.

7.

Carry out H2S drills regularly, prior to and during test periods.

8.

To produce CABA distribution list by areas and for dedicated essential staff.

9.

Provide plan to strictly police movement of personnel during risk periods (all non-essential staff remain inside accommodation).

10.

Personnel to be clean shaven whereby air tight seal on all BA equipment is not compromised.

11.

Fitting of SO2 detectors in vicinity of flare booms if required.

12.

Well test system relief valves and bursting disc vents to be piped clear of all rig structure.

Procedures 1.

No hot work permits to be issued during testing unless sanctioned by the OIM/Area Authority, after consultation with BP Rep.

2.

That all openings/doorways into areas below main deck level (i.e. column spaces, propulsion rooms) are to be kept shut. Entry into these spaces as sanctioned by OIM/Area Authority (entry permit should be considered).

3.

For gas escape accidents/incidents, ensure correct reporting procedures. a) b) c) d) e)

Telex as per Reporting Procedures in the Guidelines for Drilling Operations. BP Accident/Incident Report. PON 1 for Hydraulic Spillage. PON 11 for Well Control Incident, including the detection of H2S. OIR 9a if applicable.

4.

To ensure Mud Loggers report any H2S to BP Rep., rig floor and control room immediately.

5.

For agreed Briefing/mustering areas (2 outside, 1 inside) combined with PA instructions as to safe areas.

6.

To ensure ALL personnel understand the hazards, actions and rescue procedures regarding H2S (Register of Personnel attending Lectures).

7.

To inform interested parties regarding possible restriction to helicopter and supply vessel movements.

8.

To closely monitor wind speed and direction. Below 5 knots from any direction well to be closed in.

9.

To ensure hydrocarbon to surface at commencement of test in daylight hours only.

10.

To ensure propane cylinders (for flare pilot light) are checked regularly to provide continual supply.

Equipment 1.

Two air intakes for CABA compressor. If an electric compressor is to be used, ensure that it is connected to the emergency generator supply.


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2.

Streamers and wind socks to be positioned throughout unit to ascertain accurate wind direction.

3.

Gas and H2S sensors fitted at accommodation intakes (test that intake fans trip on detection).

4.

Minimum of 140 manhours of compressed air stored for use with High Pressure Distribution System.

5.

ALL communications systems fully operational. a) b) c) d)

PA System. Portable UHF and VHF Radios. Telephone System. Talk-Back Systems.

N.B. During test period extra portable UHF sets may be required. Ensure compatible frequencies with rig units. 6.

Sick Bay be provided with stimulant drugs, i.e. Adrenalin and Amyl Nitrate for use with H 2S affected personnel.

7.

Consideration given to provision of extra personal protective equipment as protection from Sulphur Dioxides given off from flares H2S.

8.

Cascade HP Air Line System to be rigged and fully function tested.

9.

Recommended areas covered by H2S fixed monitors (rig fixture). a) b) c) d) e) f) g)

10.

Recommended areas covered by fixed audible/visual alarms for H2S. a) b) c) d) e) f)

11.

Rig Floor. Shakers/Header Box. Mud Pump Room. Active Pits. Bell Nipple. Accommodation Vent Intakes. Well Test Area.

Rig Floor. Control Room. Logging Unit. Shakers/Header Box. Mud Pits. Well Test Area.

Recommended positions for SO2 (Sulphur Dioxide) monitoring. a) Vicinity of Flare Booms. b) Crane Pedestals. c) Accommodation Vent Intakes.

12.

Sufficient quantities of “inhibitor” and “scavenging” chemicals onboard.

General Above checklist is designed to cover concentrations of H2S in excess of 700 ppm. For lesser risk values, a reduced checklist could be considered.


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H2S (HYDROGEN SULPHIDE) PROCEDURES APPENDIX 1 PROPERTIES OF HYDROGEN SULPHIDE

Hydrogen Sulphide is a highly toxic, colourless gas with the chemical formula H2S. It is about 20 percent more dense than air. It can readily be dispersed by air movement. It is weakly soluble in water to produce a slightly acidic solution and is strongly absorbed by alkaline solutions to form metal sulphides. Hydrogen Sulphide forms flammable mixtures with air. The minimum auto-ignition temperature (260°C) occurs at a concentration of about 15 percent. At higher concentrations it burns mainly to water and sulphur and at lower concentrations to water and Sulphur Dioxide and combustion occurs with a pale blue flame. Hydrogen Sulphide is highly corrosive to certain metals. In particular materials containing copper should never be utilised. Metal sulphides are all combustible. In some cases spontaneous ignition at room temperature is possible. Hydrogen Sulphide is easily identified by its characteristic smell of rotten eggs at low concentrations 1 - 30 ppm. A noticeable odour will exist at very low concentration (0.01 ppm). At higher concentrations, it becomes sweetish and at about 150 ppm olfactory paralysis occurs when the sense of smell cannot be relied on at all. EFFECTS OF H2S Like other toxic materials, the effect of H2S depends on how long, and at what concentrations, you have been exposed to it. Your physical condition also plays a part, so it is difficult to provide a set of inflexible rules. H2S concentrations are usually expressed in parts per million (ppm’s). One part per million of water, for example, would be a teaspoonful in approximately 25 drums. In general, the body can tolerate repeated exposure to an average concentration of 10 ppm vol. H2S for a normal eight hour working day without hazard to health. This concentration is known as the Long Term Exposure Limit (LTEL). For a short period of ten minutes within that day, the level can be increased to 15 ppm vol. (Short Term Exposure Limit (STEL)). It must be stressed, however, that these are guideline figures used for monitoring. It should never be the intention for people to work in an environment which regularly contains H2S since it can never be assumed that the concentrations can be controlled. REMEMBER any sign of H2S should be treated as a warning and steps taken to detect the source of H2S and stop it. As noted above, the effect of H2S depends upon several variables; although it is correct to say that the sense of smell of an average person would be rapidly deadened at about 100 ppm, there have been cases of people who have been regularly exposed to even very low concentrations, eventually being unable to detect the gas by smell. 1.

Characteristics 1)

Deadly - extremely toxic gas.

2)

Colourless.

3)

Heavier than air. Vapour density of 1.189 compared to air (1.0). It tends to collect in low lying areas.

4)

Has a wide explosive range. 4.3% to 46% by volume in air.

5)

Burns with a blue flame to produce Sulphur Dioxide which is also toxic.

6)

Auto-ignition temperature of 500 20F (260°C).

7)

Highly corrosive to certain metals.


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Physiological and Long Term Effects As stated previously, H2S is extremely toxic at relatively low concentrations. Table 1 lists the various effects at different levels of exposure. At very low concentrations, in normal circumstances, it is absorbed through the lungs into the blood stream forming non-toxic compounds. As the level of the free radical increases it poisons the nervous system producing eventual paralysis of the respiratory centre in the brain causing respiratory failure and death. In addition H2S has a profoundly irritant effect on the eye due to the formation of sodium sulphide. Acute damage may be severe with blurring of vision and the formation of blisters. Recovery is usually complete, scarring is very rare and there are no cumulative effects. At high concentrations the sense of smell is rapidly lost, and death by respiratory paralysis is rapid if exposure continues. Though skin contact is not significant, perforated eardrums, however, have given rise to greater concern in recent years. Recent medical research now indicates that perforated eardrums do not pose any significant risk as a route for absorption of H2S. Alcohol in the blood stream enhances the effect of H2S poisoning. Delayed irritant effects on the lungs may present an acute pneumonia type inflammation, anything up to 24 hours after acute exposure, and should be treated as for Pulmonary Oedema, following contact with a Medical Practitioner. In cases successfully revived, there may be permanent nervous, brain or behavioural damage due to the lack of oxygen supply to the brain during the acute poisoning phase.

3.

First Aid The normal remedy for personnel suffering H2S poisoning is removal to fresh air, and artificial resuscitation as required. Before commencing artificial resuscitation (mouth to mouth), expel gas from victim’s lungs by pressing down on the chest. This eliminates the risk of being gassed by H2S in the victim’s expired air.

UK Operations GUIDELINES FOR DRILLING OPERATIONS

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H2S (HYDROGEN SULPHIDE) PROCEDURES TABLE 1 Physiological Responses to Concentrations of Hydrogen Sulphide

H2S Concentration in Air ppm3 by Volume4 10'

Response Can smell. Minimal effect over 8 hours.

152

Classification 1. Long Term Exposure Limit (LTEL) - 8 hour continuous exposure. 2. Short Term Exposure Limit (STEL).

10'

Minimum eye irritation.

Irritation.

152

Minimum lung irritation.

Irritation.

70 - 150

Kills smell in 3 - 15 minutes. Irritates eyes, throat and lungs.

150 - 400

Loss of smell. Dizziness. Difficult respiration. Coughing. Irritation of eyes, throat lungs. Needs prompt removal to fresh air if respiratory paralysis is to be avoided.

Injurious.

400 - 700

Coughing. Collapse. Unconsciousness. Death. Breathing will stop and death will result if not given artificial resuscitation immediately.

Dangerous. May produce severe injury or death.

700 - 1,000

Rapidly produces unconsciousness permanent brain damage possible.

Immediate threat to life.

Above 1,000

Immediate unconsciousness, death in a few minutes.

Note: 1.

Above values in ppm refer to concentrations “in air” and not “in stream”.

2.

Above values are approximate as susceptibility varies significantly between individuals exposed.

3.

LTEL and STEL are outlined in Guidance Note EH 40/84 from the Health and Safety Executive.


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H2S (HYDROGEN SULPHIDE) PROCEDURES APPENDIX 2 DRILLING FLUID AND H2S CONTROL

The drilling fluid is the primary means of preventing a release of H2S. It achieves this by: a)

Maintaining sufficient hydrostatic head to prevent H2S intrusion from the formation.

b)

Keeping H2S in the mud by converting it to sodium sulphide, provided that the pH is over 10.

c)

Removing dissolved H2S and/or sodium sulphide with a scavenger such as zinc carbonate or ironite sponge.

1.

Principles pH Control In water based mud systems, the dissolved H2S reacts with the caustic to form soluble sodium sulphide. This effect is more pronounced at higher pH. However, if the pH falls below 10, the dissolved sodium sulphide will convert back to H2S at surface and will come out of solution as a free gas. Scavengers At low pH (less than 10.5), there is an equilibrium at surface between H2S dissolved in the mud and H2S gas bubbling out. At a pH greater than 10.5, the H2S is converted by caustic to sodium sulphide and there is no H2S in solution to come out at surface. If the pH is greater than 10.5 and the sulphide levels are increasing, then H2S must be entering downhole. The mud weight should be increased to prevent this and the sulphides should be treated out by adding an H2S scavenger, e.g. Zinc Carbonate. These form insoluble zinc or iron sulphides which will not be converted back to H2S even if the pH drops. Zinc carbonate is the most commonly available and used scavenger. Approximately 0.5 lb/bbl is sufficient to treat 200 ppm H2S or sulphide ions in the mud. Large additions of zinc carbonate will adversely affect mud properties, especially rheology. This can be reduced by strict control of drill solid and by adding thinners and caustic to the mud. These should be added as a pre-mix to maintain the pH above 10.5. Alternative H2S scavengers are: • • • •

Zinc, chealates e.g. Zinc NTA, which has a high solubility hence works very quickly, although the products are very expensive Ironite Sponge (best at neutral pH) Lime can be used to buy time before more effective Zinc-based treatment Zinc Oxide

Oil Base Muds The water phase of an oil mud has a high pH (greater than 12) due to an excess of lime in the system. As in a water mud, this converts the H2S to a sulphide: in this case calcium sulphide which is insoluble in the mud. If lime in the mud is allowed to fall to zero, any future intrusions of H2S would come out of the mud at surface. The sulphide already present as calcium sulphide would not be converted back to H2S. It is essential that the lime content is monitored by the mud engineer during his mud checks and that an excess lime content of between 6 - 8 lb/bbl is maintained when H2S is expected. The lime content cannot be used as an indication of H2S intrusion. Lime can be taken out of an oil mud by CO2, or by reacting with the formation and cuttings, e.g. shales, polyhalites.


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Oil based muds have the advantage that the oil will protect steels by providing a non-conductive film on the surface and so preventing corrosion. A mud duck system cannot be used for the continuous monitoring of sulphides in an oil mud. 2.

Monitoring of H2S in Drilling Fluids There are various methods available to monitor the level of H2S contamination in drilling muds. The majority require the use of mud laboratory test facilities and are not continuous in nature (e.g. the Garrett Gas Train, and the HACH test. Although the latter is easier and quicker to conduct, it is at the expense of accuracy). None of these methods will positively identify the presence of H2S in the formations, but if the mud is close to balance, and H2S seeps into the mud, they should detect it. The most convenient method of continuous monitoring is the use of a mud duck. The Mud Duck This is inserted into the mud system header tank, from where it takes its readings. By careful setting of the alarm limits, the mud duck can give a forewarning of H2S in the mud before H2S is detected in the air at surface. It also gives an indication of the maximum concentration of H2S (in ppm) that can exist at the mud/air interface. The following readings are taken by the instrument: a)

Mud Temperature

b)

Soluble Sulphide Concentration (pHS) Readings Range to

c)

0.0 (10,000 ppm H2S) 19.9 (10-16 ppm H2S)

Reading

Interference

19 - 12

Concentration of soluble sulphides is insignificant.

12 - 9

Concentration still too small to be significant. Variations and trends are more important than absolute values.

9-7

Soluble sulphide concentration is increasing. It is advisable that zinc carbonate is added to the mud system to prevent corrosion.

Less than 7

H2S may be evolved if the pH of the mud drops. Zinc carbonate should be added to the mud system immediately.

Delphian Hazard Potential (DHP) This gives an indication of the maximum amount of H2S (in ppm) that would occur if gas broke out of the mud system. It is a measurement taken at the mud/air interface.


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Mud pH Procedures to be Followed in the Event of Changes in Mud Duck Readings i)

pH does not change. DHP gets larger. pHS gets smaller. There is build-up of total soluble sulphides and an increasing level of H2S gas above the mud. Continue operations but add zinc carbonate to the mud system. Check H2S levels are below 10 ppm. If 10 ppm H2S level is exceeded, follow relevant procedures in Section B.2.1 in the main body of this Manual. Check with Draeger toxic gas detector for possible H2S accumulations.

ii)

pH gets smaller. DHP gets larger. pHS gets smaller. Situation as a) above but the mud is also becoming more acidic, so more soluble sulphides will be converted to H2S. Add zinc carbonate and increase pH of mud as in Section 1 of this Appendix. Continue operations as long as H2S is less than 10 ppm. Check with Draeger toxic gas detector for possible H2S accumulations.

iii) pH does not change. DHP reads zero. pHS gets smaller. Indicates an increase in total soluble sulphides, but the H2S level is still below 1 ppm. This is important trend information. Any change in level of sulphides should be followed with treatment of mud as in Section 1 of this Appendix. iv) pH gets smaller. DHP gets larger. pHS does not change. Mud is becoming more acidic, so an acid gas has entered the borehole. The total soluble sulphides has not changed, so the gas is not H2S. CO2 is the most likely candidate to be the cause of the pH decrease. The DHP number gets larger due to more of the existing soluble sulphides being converted to H2S. Treat mud to maintain pH at 10.5 - 11, as in Section 1 of this Appendix. Monitor H2S levels, checking for possible accumulations with Draeger toxic gas detector. Continue operations as long as H2S level is less than 10 ppm. As will be realised, mud duck readings are qualitative and changes in trend are more important than actual recorded levels.


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Stocking of Materials For rigs working in Wildcat/Exploration areas, a stock of zinc carbonate should be held onboard. Minimum of one pallet (25 x 25 kg sacks). Under present arrangements, our mud suppliers hold a minimum stock of zinc carbonate (100 x 50 lb) and filming amine corrosion inhibitor (5 x 55 gal) in Peterhead. For rigs working in a known H2S area, the BP Representative/Mud Engineer will ensure that sufficient scavenger is onboard to allow a 0.5 lb/bbl treatment of zinc carbonate to the complete circulating system plus sufficient to neutralise a 50 bbl kick.


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H2S (HYDROGEN SULPHIDE) PROCEDURES APPENDIX 3 EFFECTS OF H2S ON DRILLING EQUIPMENT

1.

Sulphide Stress Cracking (SSC) Sulphide Stress Cracking, also known as hydrogen blistering, hydrogen embrittlement and stress cracking, is due to reaction of iron in a moist H2S environment. H2S + Fe + H2O → FeS (Iron Sulphide) + 2H (Free Hydrogen) + H2O Most of the hydrogen produced is released but, with pressure, some is absorbed into the metal. It migrates along the grain boundaries and recombines to form molecular hydrogen which occupies a larger volume than the hydrogen atoms. The hydrogen molecules cause increased internal stresses leading to blistering or embrittlement. This occurs particularly if there are any inclusions in the steel. Hydrogen blistering tends to occur in materials of an average yield greater than 95,000 psi. It occurs close to the surfaces and is characterised by visible blistering of the surface and pieces being shed from the surface. Hydrogen embrittlement occurs in materials with yield strengths of over 90,000 psi. It is a true intergranular failure of the material. It is a delayed failure, since time is required for the hydrogen to diffuse in the metal to points of high stress.

Note: H2S levels in samples will read artificially low if not measured at the time of sampling, due to H 2S absorption by metals. 2.

Factors Affecting Failure Failure of materials is affected by the following factors: -

3.

H2S concentration. Total and partial pressure applied. Metal chemical composition, strength, heat treatment and microstructure. Total tensile stress. Temperature. Time. Solution pH.

Standards Applying to Metals for H2S Situations The most commonly applied standard for metals in an H2S environment is the NACE Standard MR-01-75 Rev. 1980. This is generally accepted as the standard for all oilfield equipment. Within BP there is BP Engineering Standard 153 which extends the requirements of NACE.

4.

Metals for Use in H2S Environments The major selection criteria for any metals to be used in H2S environments is the surface hardness. The relationship of SSC and surface hardness is well documented and it is evident that metals of less than 22 Rockwell “C” Hardness Scale (Rc) are not susceptible to SSC. The second selection factor is the ultimate yield strength. This should be less than 95,000 psi.


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Metals within this range will not fail due to SSC throughout the full temperature range. However, there is evidence that stronger materials can be used over 160°F. See Tables 2 and 3. 5.

Drilling Components for Use in H2S Environments It is worth examining the various common components used in drilling in H2S environments and how they vary from standard items. Drillpipe Tubing etc. API recommends that all steel drillpipe used has a yield strength of less than 95,000 psi. Any failure is likely to occur near the surface, where the pipe is under maximum stress and does not have the protection of elevated temperatures. This restriction affects string design on deep wells. If aluminium drillpipe is used, pH must be limited to 10.5 to avoid accelerated weight loss corrosion. Tubular goods must be made up correctly to prevent stress concentrations which can cause SSC. Drill Collars These are largely unaffected by H2S because of the lower stress involved and the high operating temperatures. Annular BOPs Hydril manufacture their annulars with materials of hardness less than Rc22 to permit use in H2S. The selection of packing units is governed by drilling fluid type rather than H2S. However, H2S will reduce the service life of the material. BOPs Both API and NACE lay down standards for BOPs in H2S service. The basic requirement is for materials of hardness less than Rc22. This is not always possible for the rams. For blind and pipe rams, material up to Rc26 can be used. For shear rams, the blades must be of high strength, high hardness material. This makes them susceptible to SSC. Rubber goods in the BOPs need to be changed to nitrile elastomers. Wellheads and Valves for H2S These are produced generally to NACE MR-01-75, however some companies prefer to tailor valves to specific requirements. Welding of Materials On H2S equipment, most connections are made by welding or welded flanges. The important point is that after welding the Head Affected Zone (HAZ) must be stress relieved by tempering. The hardness of the HAZ and base metal must be less than Rc22. The welds must be qualified to appropriate API or ASME specifications. This precludes any field welding.

6.

Precautions Against H2S Corrosion An advantage in drilling is that the service environment can be controlled. Also operations take place at high temperatures which reduces H2S attack.


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Drilling Fluids A number of methods can be used to control the effects of H2S on the drill string: a)

Use of sulphide scavengers, to chemically absorb the H2S, e.g. Ironite Sponge or Zinc Carbonate.

2)

Increasing pH over 10 to neutralise H2S. Can result in sulphur liberation in the mud.

3)

Using oil based muds to form a non-conductive oil film on the steel.

Completion Fluids A recommended method is to use oil or oil based fluids on completions. Corrosion Inhibitors Corrosion inhibitors should be used to coat all the pipe when it is being pulled out. A filming amine type corrosion inhibitor, e.g. Coat 415 or Ami-Tec, should be applied by slugging the pipe every 3rd connection with 2 bbls of diesel containing 5 gal/bbl corrosion inhibitor. When tripping in the hole, the same solution should be sprayed on the outside of the pipe. Inspection of Components It is difficult to inspect items exposed to H2S for possible SSC, due to the intergranular nature of the attack. If blistering occurs or the SSC is associated with inclusions in the metal, it can be detected by ultrasonics or x-ray. Failure due to SSC usually occurs early in equipment life, thus if an item is in service for a while it is unlikely to fail.

For 80°C (175°F) or Greater

Tubing and Casing

Tubing and Casing

Tubing and Casing

5A Gr H-40(3) J-55 & K-55

API Spec.

API Spec.

5AC Gr C-75 & L-80

Proprietary Q&T Grades with 110 ksi or less maximum yield strength.

API Spec.

4A Gr N-80 (Q&T) 5AC Gr C-05

5A Gr H-40 & N-80 5AX Gr P-105 & P-110

Proprietary Q&T Grades to 140 ksi maximum yield strength.

Pipe(4) API Spec.

5L Gr A & B 5LS Gr X-43 thru X-65(7) 5LX Gr X-42 thru X-65(7)

ASTM

A-53 A-106 Fr A, B, C A-333 Gr 1 & 6 A-524 Gr 1 & 2 A-381 C1 1 Y35-Y65(7)

Drill Stem Materials(5) API Spec.

5A Gr D & E 5AX Gr X-95, G-105 S-135

Rev.

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0120/GEN

Impact resistance may be required by other standards and codes for low operating temperatures. Continuous minimum temperature; for lower temperatures, select from Column 1. 80 ksi maximum yield strength permissible (latest revision of API 5A includes this requirement). Welded grades must meet the requirements of Sections 3 through 8. For use under controlled environments as defined in Paragraph 11.1.2. Maximum drilling fluid pH = 10.5. Grades X-56 through X-65 and Y56 through Y65 shall have a maximum hardness of HRC 22.

:

(1) (2) (3) (4) (5) (6) (7)

Page

API Spec. 7 Aluminium 2014-T6 (UNS A92014)(6)

UK Operations

For 65°C (150°F) or Greater (2)


For All Temperatures (1)


OPERATING TEMPERATURE

BP EXPLORATION

Consult the NACE Specification for full information. Materials listed in this table are acceptable under environmental conditions noted.

SUBJECT:

TABLE 2 - Acceptable API and ASTM Specifications for Tubular Goods


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H2S (HYDROGEN SULPHIDE) PROCEDURES TABLE 3 Acceptable Materials for Sub-Surface Equiment for Direct Exposure to Sour Environment

USE

MATERIAL

Drillable Packer Components

Ductile Iron (ASTM A-536, A-571)

Drillable Packer Components

Malleable Iron (ASTM A-2000, A-602)

Compression Members

Gray Iron (ASTM A-48, A-278)

All

9Cr-1Mo

(1)

(ASTM A-199 Gr T9, A-200 Gr T9, A-276 Gr F9)(1) ASTM A-213 T9

Maximum hardness of HRC 22. ABSTRACT FROM : NACE MR-01-75 (1980).


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H2S (HYDROGEN SULPHIDE) PROCEDURES APPENDIX 4 LIST OF USEFUL CONTACTS

NOTE:

This list is not exclusive and may be added to later. Inclusion in this list does not imply approval by BP.

Protector Saver, 225 Ash Road, Aldershot 01252-344141/342325 Safety Concepts, Camco House, Viking Road, Gapton Hall Industrial Estate, Great Yarmouth. 01493-440728 OPITO, Forties Road, Montrose. 01674-66250 Draeger Ltd, Kittybrewster Industrial Estate, Blyth, Northumberland, NE24 4RG. 01670-352891

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USE OF EXPLOSIVES IN DRILLING OPERATIONS

INTRODUCTION TO OFFSHORE EXPLOSIVE TECHNIQUES Explosives can be divided into two broad categories - low and high explosives.

1.1

Low Explosives Low explosives are employed where their ability to produce large volumes of gas is required as a source of energy. This can be as a propellant to force a projectile in the desired direction or as a means of inflation, e.g. in a packer. Low explosives are said to be deflagrating and are initiated by ignition (although this may start as impact, e.g. percussion cap). By comparison with high explosives, they generate a slow, heaving action.

1.2

High Explosives High explosives are used where an instantaneous shattering action - brisance - is required. They are initiated by detonation, i.e. by an explosion, and the speed and power of the means of detonation is reflected in the speed of the shock waves produced by the high explosive.

1.3

Detonators The selection and correct use of an appropriate combination of detonators and accessories is essential in achieving a safe and effective result, whilst minimising the physical and environmental hazards.

1.4

Primers Primers are used to boost the detonation wave for efficient propagation to the less sensitive explosive charges. There are special purpose boosters available, but in most cases detonating cord is used as the priming medium.

1.5

Initiation Methods Detonators are the most sensitive components in the explosives train. Modern systems have been devised to decrease their sensitivity to handling and to make operations involving explosives safer and more predictable. For underwater explosives operations, the use of straight-forward electrical detonators, which are prone to the effects of radiation, has virtually been discontinued. As these detonators could be prematurely triggered by voltages induced in the firing circuit from radiating sources such as radar, radio, navigation systems, etc., they required radio silence at critical periods. They have been replaced by three basic types of detonator: a)

The high threshold detonator which employs a resistor to filter stray voltages.

b)

The magnetically induced detonator which utilises a magnetite ring to induce a current from a predetermined cycle surged through a circuit. This momentarily turns the ring into a transformer resulting in initiation of the detonator.

c)

The exploding bridge wire system which depends on a high voltage and high amperage applied over a short time. This ruptures a bridge wire at such a velocity as to produce a detonating wave.

These systems have been developed to provide a higher degree of safety andreliability. 1.6

Shaping a Charge An explosion exerts force in all directions. Although the explosion from a cartridge in a firearm may seem to direct all the force towards propelling the projectile along the barrel, this is not so. Much of the energy is absorbed in the breech or chamber, and more is spent in the recoil. It has been made

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possible to use all the energy shaped or focused into a jet by having the explosive packed behind a conical liner. This effect is illustrated in Figure 1.

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, ,,

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FIGURE 1

SHAPED CHARGE - FORMATION OF JET AND SLUG

METAL LINER

(1) BEFORE FIRING

EXPLOSIVE

(2) DURING FIRING

DETONATION FRONT

(3) DURING FIRING

(4) AFTER FIRING

2179 /147

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2.

THE APPLICATION OF EXPLOSIVES IN DRILLING

2.1

Perforating Perforating was originally carried out using a propellant cartridge to fire a solid ball into the formation through tubing. This method is still available, but is little used. The Kinley Perforator, however, still uses this principle to perforate tubing where bridging problems interrupt circulation. Nearly all perforating is now carried out using shaped charges run on either wireline or drill pipe. In the former method, initiation is by means of a detonator fired by the wireline, and in the latter by firing a cartridge by means of impact or pressure. In both cases a series of shaped charges is detonated virtually instantaneously by means of detonating cord, itself detonated by the described initiation methods.

2.2

Pipe Back-Off Pipe back-off is achieved by setting off a controlled explosive jarring action to loosen a selected joint.

2.3

Pipe Cutting Pipe cutting is possible by means of a shaped charge which has an outward facing circular liner providing all round shaping of the charge to give a clean cut on detonation (Figure 2).

2.4

Collar Cutting Collar cutting is more difficult to accomplish because of the thickness of metal involved. A technique using a collision charge is used. This involves a container of explosives with a detonator above and another below the charge (Figure 3). Simultaneous detonation results in two shock waves converging and colliding with the result that they force each other sideways, thus cutting the chosen collar.

2.5

Side-Wall Coring Side-wall coring is used to obtain small samples of the formation. It is accomplished by firing a hollow “bullet” into the formation. The bullet, with its formation sample, is held captive by short cables and is recovered by pulling the gun out of the hole.

2.6

Junk Shot Where undrillable junk, e.g. twisted-off rock bit, is preventing drilling and cannot be fished, a large shaped charge can be used to shatter the obstruction. The fragments are then retrieved with a magnet or junk basket. The junk shot is either run on drill pipe or wireline. A built-in stand-off ensures that the charge is at the correct distance from the obstruction.

2.7

Wellhead Recovery from a Drilling Rig On abandonment, wellhead recovery from a drilling rig can be accomplished using explosives to sever casings in much the same way as collar cutting, but using a much larger collision charge (Figure 4).

2.8

Wellhead Removal from a Diving Support Vessel (DSV) Wellhead recovery from a Diving Support Vessel (DSV) is carried out when the rig has moved off location. It is not unusual to contract a DSV to recover more than one wellhead in an operation. The method of severing the casings is similar to collar cutting. The main difference is that divers guide the charge assembly into the hole as it is being lowered on the load-line from the DSV. A “cross-piece” is fitted to the load-line to give the correct distance the charge must be in the hole, which is usually 5m (Figure 5). When the Diving Supervisor is satisfied the charge is correctly placed, he will recover the diver/diving bell to the surface before the charge is fired. If a corrosion cap is set, the divers will be required to remove it before cutting operations begin.

,,,, ,,,,,,, ,,,,,,, ,,,,,,

DRILLING MANUAL

,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,,

EXPLOSIVE ,,,,,,,,,,,,,,,,,, ,,,,,

,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,

JET TUBING CUTTER

,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,

SUBJECT:

,,,, ,,,,,,,,,, ,,,,,,, ,,,

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USE OF EXPLOSIVES IN DRILLING OPERATIONS FIGURE 2

JET CASING CUTTER

FIGURE 3

SANDLINE (OR DRILL-PIPE)

COLLAR CUTTER

FIRING LINE

DETONATORS

2179 /146

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USE OF EXPLOSIVES IN DRILLING OPERATIONS FIGURE 4 WELLHEAD SEVERING CHARGE DRILL PIPE FIRING MODULE INITIATING CABLE VENTED TOOL ATTACHMENT

BALLAST CONTAINER EXPLOSIVE CONTAINER CASINGS

FIGURE 5 DIVER GUIDING CHARGE INTO WELLHEAD

LOADLINE FIRING CABLE

CROSS PIECE

DIVING BELL

DEPTH CHARGE IN THE HOLE BALLAST DRUM EXPLOSIVE CHARGE

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When the wellhead has been severed the diver will connect the DSV crane to the base. It is then recovered to the surface. The crane should be rated to a minimum of 60t SWL to overcome the weight of grout, cement and effects of suction. 3.

INFORMATION REQUIRED TO PERFORM EXPLOSIVE OPERATIONS The work to be done must be specified in sufficient detail to allow the explosives service company to produce procedures. The procedures should be submitted to Drilling for approval and any major changes to the procedures must be agreed before implementation.

3.1

Perforating A large range of shaped charges is available to suit different tubular sizes. A charge’s performance is governed by the angle of the conical liner. It is the responsibility of the Petroleum Engineering Department to: •

Specify which charges are required to optimise performance in the formation to be perforated.

•

Provide the explosives service company with information on the zone or zones to be perforated and the spacing and direction of the charges.

•

Provide an engineer to look after their interests on the rig during perforating operations.

The Drilling Supervisor is responsible for the running of the operation.

Note: Top-drive isolation - see Note 4.3. 3.2

Pipe Back-Off Assuming the Free Point Indicator tool has indicated the free point, it will be necessary to work out the point at which back-off is to be attempted. Since this is most likely to be successful at a joint which is normally broken when tripping, the joint nearest above the free point should be identified and its depth given to the service company. A discussion should take place on the type of thread, torque used in make-up and the reverse torque turns required to achieve back-off on firing the jarring charge.

3.3

Pipe Cutting Where back-off is unsuccessful, a severing charge can be used at the chosen joint. It is obviously easier to cut the drill pipe in the middle section rather than at a connection.

3.4

Collar Cutting The information required by the service company is again the identification of the most suitable free joint.

3.5

Side-Wall Coring The cores are required by Geology Department who will specify the depths at which cores are to be obtained and will witness the operation. Drilling will be responsible for the running of the operation.

3.6

Junk Shot The explosives service company require to know the nature of the junk material in order to decide the size of junk shot required.

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Wellhead Recovery from a Rig Information required by the explosives service company includes: a) b) c)

3.8

Number of casings to be cut. Grade of casings to be cut. Water depth.

Wellhead Recovery from a DSV a) b) c) d) e) f) g) h)

Well locations and number. Number of casings. Grade of casings. Water depth. Condition and weight of wellhead. Proximity to other wellheads, debris, etc. Where the wellheads are to be off-loaded. Depth of cut required.

4.

SAFETY CONSIDERATIONS

4.1

General The following safety points offer guidance to the BP Drilling Supervisor and OIM’s involved in overseeing explosives operations, and should be read in conjunction with BPPD Standard HS&E Regulations, Chapter 30.

4.2

Responsibilities The BP Drilling Supervisor and OIM in an operation involving the use of explosives have a responsibility to be fully aware of all the aspects and limitations connected with their applications, and a duty to ensure the rigid enforcement of safety regulations. An Explosives Engineer experienced in the safe handling and use of explosives should be placed in overall charge of the explosives operation and be responsible to the BP Drilling Supervisor/OIM for its conduct and the health and safety of all personnel involved. His responsibilities will include: •

Advising the OIM/Drilling Supervisor on aspects of the explosives operation.

•

Ensuring the explosives are “fit for purpose” and correctly stored.

•

Making-up and deploying the charges.

•

Supervision of all persons involved in explosives handling.

•

Implementation of the Service Company Regulations.

•

Ensuring that all explosives that are to remain onboard are correctly stored and accounted for.

•

Preparing surplus explosives for back-loading and ensuring that they are correctly labelled and manifested.

The allocation of responsibility must be clear and should be published and distributed to ensure that all the appropriate parties are informed.

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Ready Use Storage on Site The storage area selected for the explosives and accessories required to be used on site should fulfil the following minimum requirements: •

Remote from any Hazardous Area.

•

Remote from the living accommodation.

•

Remote from any source of heat or flame.

•

Insulated against shock.

•

Protected from blast debris.

•

Well ventilated and dry.

•

Remote from possible Electro Magnetic emission hazards.

Note: On rigs equipped with an electric top-drive, the top-drive motor must be electrically isolated before running explosives on electric wireline. •

Free of grit, or the explosives must be mounted on wooden pallets with a grit free surround.

•

If a storage area is on a vessel, it must have wooden walls and floor and offer secure storage in the event of rough weather.

•

The exterior should be painted red with the word “DANGER” painted by the door of the magazine or container. Appropriate hazard labels should also be displayed on the vertical sides of the magazine or container.

In addition, the area must be clearly marked with warning and “No Smoking” signs in white letters on a red background. There must be separate storage for detonators, and all storage areas must be secured and locked against unauthorised entry. 4.4

Issue of Stores The OIM should authorise all issues of explosives and accessories and ensure that:

4.5

•

The explosives are not approached or handled by unauthorised persons.

•

Surplus stores are returned to the magazine/explosives container prior to firing.

•

The “explosive register” is kept up-to-date and all issues and returns noted, including material damaged and destroyed.

•

Detonators are drawn only immediately prior to firing by the Explosives Engineer.

Explosives Register An explosives register shall be kept by the OIM for the purpose of complying with the Health & Safety at Work etc. Act 1974, and shall be maintained at those locations where the explosives certificate holders are based. It shall contain the following information: a) b) c) d)

Details of all receipts. Details of all issues, and where being used. Details of all explosives used in each operation. Details of all misfired shots.

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Details of all explosives returned. Details of disposal and destruction of old stock.

After Firing On completion of explosives work, all unused and misfired explosives must be returned to the store/freight travel container and the “Explosives Register” updated. Any shortage must be the subject of an immediate enquiry conducted by the OIM. Unless this resolves the situation, the Police must be informed by the OIM.

Note: Explosives must not be stored on offshore installations for longer than is absolutely necessary. Explosives so stored shall be the minimum quantity deemed necessary to carry out the job. 4.7

Radio/Radar Silence During Explosives Operations During operations involving explosives, sources of “stray” induced currents, e.g. welding sets or cathodic protection which may be deemed as possible “triggers” to detonators, must be shutdown/ switched off before making up any explosive tool or device (see 4.3 - electrical isolation of top-drive). These limitations must be enforced from the time when the Electro Explosives Devices (EED’s) are removed from the store until the time when the armed charge is 100 metres or more below the seabed or ground level. The limitations must be re-imposed at the 100 metre level when the shot, fired or not, is being brought back to the surface, until it is declared safe by the Explosives Supervisor. The OIM is responsible for ensuring that the correct procedures are instituted by way of the Control Room and Radio Operators (see BPPD HSE Regulations, Appendix 30.3 “Radio Silence Whilst Operations Involving the Use of Explosives are in Progress”). The offshore installation’s standby vessel should be in visual signalling distance of the installation during such periods of radio silence.

4.8

Safety Distances An underwater explosion will create shock waves and other forces which could damage rigs, installations and vessels. To avoid damage, tables have been evolved by vessel and rig owners indicating safe distances from explosions. Dependent on the weight, type and the location of the charge, the Explosives Engineer will calculate the predicted pressure and bubble effects. He will advise the OIM/Master of the required safety distance from the charge. The BP Drilling Supervisor should ensure that the safety distances are adhered to. The intended weight and type of explosives will be determined in the approved procedures. If it is considered necessary by the Explosives Engineer to increase the agreed charge weight or type of explosives, it must be justified and endorsed by the Drilling office. The maximum weight of explosives used during wellhead severing operations is about 35 lbs (TNT equivalent). It should be noted that the effects of the shock waves on the hull of a vessel or rig from 35 lbs TNT set in the hole for wellhead severing operations is approximately equal to 2 lbs TNT detonated on the seabed.

4.9

Legislation and Guidance a)

XTC Drilling Policy & Guidelines Manual.

b)

Petroleum (Production) (Seaward Areas) Regulations, 1988.

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c)

The Offshore Installations (Construction & Survey) Regulations 1974.

d)

The Offshore Installations (Operational Safety Health & Welfare) Regulations 1976.

e)

The Explosives Acts 1875 and 1923.

f)

UKOOA Council Minutes of 13th June 1979.

g)

Continental Shelf Operations Notice No. 11.

h)

The Classification and Labelling of Explosives Regulations 1983.

i)

BPPD Standard HS & E Regulations, Chapter 30.

j)

D.O.T. “Carriage of Dangerous Goods in Ships” (The Blue Book).

k)

The Air Navigation (Dangerous Goods) Regulations, 1984.

l)

The Dangerous Substances in Harbour Areas Regulations, SI 37/87.

m) Exemption from the Requirements of Article 44 of the Air Navigation Order 1985, CAA Ref. 000583. n)

BPPD (HTH) Safety Flash 3/86. Perforating gun trapped pressure hazard.

5.

RESTRICTED AREAS

5.1

Rig Floor When operations are about to begin on the rig floor, the area must be cleared of all non-essential personnel. While the Explosives Engineer is making up the charges or mixing two-part liquid explosive, only service company operative(s) and a rig supervisor (OIM’s competent person or BP Drilling Supervisor) should be present.

5.2

DSV When operating from a vessel, the designated area where the explosives container and magazine is sited should be restricted to personnel as for rig floor operations.

6.

DIVING OPERATIONS USING EXPLOSIVES

6.1

When divers are required to place explosives, i.e. wellhead removal from a DSV, they will remain under the control and responsibility of the Dive Supervisor. The Dive Supervisor will take advice from the Explosives Supervisor as to how and where the charges will be deployed and placed. The Dive Supervisor must have custody of the dynamo exploder and firing key at all times when the bell is unmated from the dive system and/or when divers are in the water. The bell must be on-deck or mated to the system before the explosives are fired.

6.2

Commercial divers must never be called upon to handle unexploded bombs, mines or other military explosive devices. If explosives are found during diving operations, the Drilling Supervisor/OIM should contact his management during working hours and the Dyce Operations Control Centre (to contact the Duty Diving Operations Superintendent), out of working hours. The site should be cleared until the appropriate authorities declare it safe to continue work.

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Diving/Perforating Operations It is acceptable to carry out diving and perforating operations simultaneously providing the following precautions are observed. The Dive Supervisor must satisfy himself that the rig is observing radio silence. He should ensure that the “firing key” is removed from the firing panel and in his custody. The Diver is to return into the bell during the period of radio silence including the retrieval of the gun to the surface. The Diver must return to the bell stage before the gun is fired.

Note: It is advisable to position the bell as far as practicable from the wellhead during perforating operations. 7.

PRECAUTIONS DURING EXPLOSIVES OPERATIONS Prior to explosives operations, ensure that the following measures are taken: a)

Inform all shipping and installations in the area that subsea explosives operations will commence in approximately 30 minutes (repeat at 5 minutes before firing).

b)

Withdraw hot work permits for welding work.

c)

Ensure that there is no smoking in the area where charges are being made up.

d)

Ensure that radio/radar restrictions are in force.

e)

Ensure that fire extinguishers are placed near the explosives container.

f)

Ensure that warning signs are prominently placed and red flags are displayed.

g)

Ensure that rig/vessel transducers, transponders (including radio and radar DP beacons) are hoisted inboard and shutdown. If acoustic beacons are used as in DP vessels, there is no need to shut them down.

h)

Broadcast to all personnel that explosives will be fired within 30 minutes, and the siren will be sounded 1 minute before blasting.

i)

Ensure that prior to helicopter operations the rig/vessel instructs the pilot to switch off all of the aircraft’s transmitting systems.

j)

Ensure that the vessel/rig is the correct distance from the charge.

k)

Ensure that all loose explosives and detonators are correctly stored.

l)

Ensure that, on completion of operations, shipping and installations are informed.

m) Ensure that, on completion of operations, it is broadcast to personnel that it is “all clear”.

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8.

EXPLOSIVES HANDLING, LEGAL AND PROCEDURAL ASPECTS

8.1

Legal The Legislation requires that there be written instructions “specifying practices to be observed to ensure the safety of the installation and safe use of the equipment thereon”. This is the responsibility of the Installation Owner. The written instructions should include: Appointment of a “competent person” who will be responsible for the handling, storage, issuing, use of, documentation and transport of explosives within the sphere of responsibility of the OIM. As Concession Owners, BP have the responsibility to ensure that the Installation Owner (OIM) carries out his duties and provides a Safe System of Work.

9.

PROCEDURES AND AUDITS

9.1

Audits For all explosives operations, BP will contract a company specialising in such work. The explosives service company will be audited by BP to ensure that they are responsible and capable of carrying out work on BP sites and that they meet the legal and BP requirements. The audit will be carried out annually or as deemed necessary by BP.

9.2

Requirements of Audits A requirement of the audit is that the explosives service company submit to BP copies of their Company details and procedures, including: • • • • • • •

9.3

Safety Manuals and Contingency Plans. CV’s of Operations staff. Management Organigram and Responsibilities. Base Facilities. Magazine and Explosives Storage Facilities. Transport arrangements for explosives to and from BP Sites. Training methods for Company personnel.

Procedures The explosives service company will be required to submit details and procedures for the particular worksite and operation, including: • • • • •

Safety and Contingency Plans. Personnel, Responsibilities and Qualifications. Work plan including type and weights of explosives. Certification of Plant and Equipment. Transport and Storage of Explosives.

When the details and procedures have been agreed by Drilling Department, they will be copied to the BP Drilling Supervisor onsite and should be considered as the formal Guidelines for the work. Any major changes from the agreed procedures should be confirmed with Drilling Department before implementation. While BP have a responsibility to ensure that the work is carried out safely in accordance with a permit to work and a written safe procedure etc., we should not interfere in the technical expertise for which we have contracted and for which the explosives service company is responsible in law.

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Post Operations Report On completion of the work, the explosives operating company will compile an “Operations Report”. The Drilling Supervisor should ensure that he receives a copy of the report, and forwards a copy to LOG (Explosives Advisor) for information and filing.

9.5

Offloading and Storage The area in which explosives are stored must be chosen to comply with legislation and be marked on the rig plans as required by Legislation (SI 1019). Consignments of explosives arriving on the installation should be craned to this dedicated area, and, if not already in weatherproof containers, the contents should be transferred to the explosives store and the explosives register updated accordingly. If the consignment must be kept elsewhere on the rig (e.g. carrier guns), then that place must be demarcated. In all cases, the crane operator must be aware that he is handling explosives which may be sensitive to impact.

10.

PERSONNEL

10.1

Manning Levels For safety and operational reasons consideration must be given to the practice of employing only one Explosives Operator on sites where it can be expected that he will be working for abnormally long periods. An error due to tiredness could be catastrophic. It is desirable to deploy a minimum of two explosives personnel, one being the Explosives Engineer with specific duties and responsibilities, the other being his assistant with sufficient knowledge and maturity to carry out work unsupervised upon the Engineer’s instructions.

10.2

Qualifications For wellhead severing operations, demolition and cutting work, the Explosives Engineer will be an individual Member of the Institute of Explosives Engineers with at least three years experience of offshore explosives work. Other personnel working to the instructions of the Explosives Engineer should ideally be associate Members of the Institute, or experienced in offshore explosives operations. When wireline operations are used with explosives, i.e. perforating, etc., it is unlikely that the personnel will need formal explosives qualifications. The Drilling Superintendent or others responsible for contracting explosives users should use their discretion in ensuring that the operators are suitably qualified and experienced for such specialist operations. Only personnel who have been approved for explosives work will be allowed to work on BP sites.

10.3

Log Books A scheme has been introduced by the major explosives operating companies and in conjunction with the Institute of Explosives Engineers whereby all operatives keep a Log Book of their work experience and training. Since BP are required by law to employ offshore only those experienced in that operation, the log book will assist greatly in ensuring that operatives proposed in contract bids comply with this requirement. The Log Book is not a legal document, but it will offer the onsite BP Drilling Supervisor the opportunity to assess the experience and capabilities of the explosives operatives under his control.

BP EXPLORATION


Section

:

0160/GEN

Rev.

:

2 (7/91)

Page

:

15 of 16


REPORTING PROCEDURES When near seabed use of explosives is planned the MOD must be informed by telex. This will be undertaken by the drilling office. Refer to the BP Reporting Procedures Manual for the required telex details.

12.

CONTROL AND MOVEMENT OF EXPLOSIVE MATERIALS

12.1

Road It is essential that a record of control shall be kept of the movement of explosive materials. A simple system has been devised to ensure that this control is maintained. It is the responsibility of the Field Group/Divisional Safety Officer to maintain a record of this control but this does not preclude interested parties maintaining a similar control should they so wish. The driver should have a statement of the quantity and description of the explosives being carried. This should be checked with the person taking delivery who should sign the statement as a form of receipt for the driver. The Department, Contractor or Supplier concerned in the despatch of explosive materials will advise the Field Group/Divisional Safety Officer, Stores Department (Receiving Warehouse) and the recipient at the final destination by telex giving the following information: a)

Nature of explosives, e.g. shaped charge, flare, rockets, etc.

b)

Time and date sent and by what mode of transportation.

c)

Destination - final and interim.

Where the explosive material is handled at interim destinations, the same procedures will be carried out. When the explosive material has reached its final destination, the recipient shall forward a telex confirming its receipt. A maximum 6 hour time delay is allowed from each ETA at each given destination before a search action shall be initiated by the Field Group/Divisional Safety Officer in conjunction with Stores Department to establish the whereabouts of the explosive material and the cause of delay. 12.2

Sea The explosives service company must present the explosives package(s) at the BP Base properly packaged, labelled and documented to comply with the IMDG Code. On completion of the explosives operations, the senior operative must prepare his stores for the return trip and assist the OIM (or his competent person) with the documentation, labelling, etc.

Note: When explosives are backloaded from the rig, the BP Drilling Supervisor/OIM should ensure that a telex is sent to the BP Base, who will then advise the service company of the ETA so that they may collect their explosives on the vessel’s arrival. 12.3

Air Generally transportation of explosives is forbidden in both passenger and cargo aircraft. However, the Civil Aviation Authority granted certain exemptions from the Air Navigation Order 1985, quote: “Please find enclosed an exemption from the above order enabling ............... Ltd. to carry limited quantities of

BP EXPLORATION


Section

:

0160/GEN

Rev.

:

2 (7/91)

Page

:

16 of 16


explosives on board helicopters engaged on offshore operations in support of the oil and gas industries” - unquote. Copies of the CAA exemptions are distributed to Drilling Department by LOG as required. The limited quantities of explosives allowed to be transported will vary depending on classification. In compliance with legislation all packaging and documentation must comply with the “Technical Instructions for the Safe Transport of Dangerous Goods by Air” approved and published by decision of the Council of the Inter- national Civil Aviation Organisation - the ICAO Handbook. Both the helicopter company and the explosives operating company have responsibility for the packaging and labelling of the explosives to be transported. The BP Central Receipt Point (CRP) have staff trained to standards required by ICAO to receive and ensure that the cargo is correctly labelled, etc. It is not acceptable practice to use BP transport to collect explosives from the explosives operating company base.


SUBJECT:


Section

:

0300/GEN

Rev.

:

7 (09/96)

Page

:

1 of 1

DAILY REPORTS FROM RIG

ALL REPORTS TO BE SUBMITTED TO THE BP OFFICE BY ON-SITE STAFF ARE NOW INCLUDED WITHIN THE WELL OPERATIONS REPORTING GUIDELINES (PSR-W28).


SUBJECT:


Section

:

0310/GEN

Rev.

:

3 (09/96)

Page

:

1 of 1

WEEKLY REPORTS FROM RIG



SUBJECT:


Section

:

0320/GEN

Rev.

:

7 (09/96)

Page

:

1 of 1

GENERAL REPORTS FROM RIG



SUBJECT: 1.


Section

:

0400/GEN

Rev.

:

3 (3/95)

Page

:

1 of 2

WELL CONTROL PROCEDURES

WELL CONTROL POLICY In accordance with Section 2.6 of the BPX Drilling Policy, dated 12/92, the BPX Well Control Manuals (Volumes I and II) constitute policy. However, if a formal and specific dispensation from this Policy has been granted, an alternative (contractor's) procedure (well shut-in method, etc.) MAY be followed in preference.

2.

DRILLING In addition to the above referenced Well Control Policy, the following statements apply:

2.1

It is a primary responsibility of the BP Drilling Supervisor to ensure that BP Well Control Policies and Procedures are adopted.

2.2

The subject of Well Control must be discussed with the Contractor Toolpusher to ensure:

2.3

2.4

a)

BP Well Control Policies as set down in the Drilling Policy Document are understood and adhered to by supervisory personnel.

b)

BP Well Control Procedures as set down in the BP Well Control Manual are understood and correctly implemented.

c)

Standing Orders for Well Close-In Procedures have been posted at the Driller's position, and that all responsible personnel fully understand them.

d)

All relevant rig equipment is competent and adequately tested to ensure that a flowing well can be controlled.

e)

The well status and all operations are constantly reviewed to ensure that the ability to control the well is not impaired.

The following equipment must be available while drilling: 1)

Hydril drop-in BOP located in the BHA. Dart to be kept in Driller’s doghouse (refer to Section 5410/GEN).

2)

Full opening kelly cock to be installed below the kelly at all times. Back-up to be available on rig floor.

3)

If available, a suitably rated circulating head with short joint of S135 drill pipe below to be available for immediate installation when drilling or tripping. Also sufficient length of suitably pressure rated circulating hose to be available for use with the circulating head.

4)

Back-up manual adjustable drilling choke spares to be available and stored near the choke manifold.

5)

A drillable bridge plug with drill pipe running tool and retrievable bridge plug/storm valve assembly to be available on board for 13 3/8” and smaller casings to cover the event of having to pull the BOP stack with hydrocarbon bearing zones in open hole.

The BOP stack configuration must conform with Company Policy. A diagram showing ram positions in the stack and the depths to each ram below rotary table and below MSL is to be clearly displayed. On semi-submersible units a procedure for estimating the tidal height is to be immediately available using tide height charts or guidewire markers. Depths can be accurately checked when testing the BOP.


SUBJECT:


Section

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0400/GEN

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:

3 (3/95)

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WELL CONTROL PROCEDURES

2.5

On subsea BOP stacks both control pods on the BOP stack must be operational for drilling to continue. If one pod fails then the pipe should be hung off with the bit at the shoe and the well closed in (including shear rams) until the repair is completed. If both pods fail then a cement plug or bridge plug must be set prior to any repair work. In certain circumstances, drilling or other open hole operations may be allowed to continue after consultation with the drilling office.

2.6

The well will be flow checked always prior to tripping, after pulling into the casing shoe and before the BHA enters the BOP stack. The minimum length of a flow check will be 15 minutes. Ensure that the hole fill pump from the trip tank is running continually and that the trip tank level indicator is operating smoothly. On semi-submersible units this will help to overcome the effects of rig heave. The Drilling Supervisor is to be on the rig floor to observe the first 10 stands pulled off bottom.

2.7

When swabbing is anticipated on trips, avoid pumping a heavy pill which will disguise the swabbing. Instead, pump the pill when swabbing has stopped, or at the shoe.

2.8

Mud weight while drilling should be sufficient to give at least 200 psi overbalance on known or predicted formation pressures. On semi-submersible units, in most situations the mud weight should afford 100 psi overbalance on formation pressure with the riser removed. The well will always be drilled in a manner which allows primary well control to be maintained by the use of mud weight.

2.9

On exploration/appraisal wells, one mud pit (typically 300 bbl) of heavy mud must always be available with mud weight 0.25 SG higher than the drilling mud weight, and with similar rheology.

2.10

All pit level monitoring equipment must be observed at all times when in open hole. Any pit increase must be checked, and the derrickman must always inform the driller and the mud loggers when changing tank levels.

2.11

The degasser is to be operated daily and always during bottoms up circulation after tripping. The equipment must be maintained and operating efficiently.

2.12

At the start of his tour the driller must check that choke manifold valves, and subsea valves on floating units, are correctly set and that the line from the chokes to the degasser is open.

2.13

When running casing, a casing to drill pipe crossover (to allow casing to be landed on the rams on floating units) and a casing circulating swage (to allow casing to be circulated) are to be available on the rig floor.

3.

WELL CONTROL RESPONSE PROCEDURES

3.1

In the event of a well control incident, and once the well has been shut-in using the appropriate technique/procedure, all appropriate installation staff must be informed (e.g. OIM, Toolpusher, BP Drilling Supervisor, etc.).

3.2

The BP Drilling Supervisor/Representative must contact the appropriate DS (or Duty DS if outwith normal office hours). The OIM must contact the appropriate onshore control centre (the DOCC in the case of Dyce-based operations), and if appropriate, the Coastguard. The above steps are in accordance with the first few essential steps as detailed in the 'Well Incident Response Procedures", a controlled manual issued by PSR (reference number PSR-W20). This also contains further detail of how, through activating the Well Incident Group (WIG), the onshore organisation will provide appropriate technical support. This group does not duplicate any aspect of the operational support (evacuation and rescue of site personnel, etc.) provided through activation of the ERC (Emergency Response Centre) in BP's Dyce office. It should be borne in mind that, in addition to covering incidents during drilling operations, the Well Incident Group procedures also apply to ANY well-related incident during well completions, workovers, maintenance activities, and non-rig well servicing operations.


SUBJECT: 1.


Section

:

0402/GEN

Rev.

:

0 (05/96)

Page

:

1 of 2

WELL CONTROL IN HIGH ANGLE OR HORIZONTAL WELLS

KICK PREVENTION AND DETECTION All techniques used in vertical wells for avoiding and detecting kicks can be applied to high angle or horizontal wells. Kick intensity is potentially high when drilling a horizontal well due to the longer exposed hole section to the producing formation. The swab/surge pressure is relatively higher in a high angle or horizontal well. To prevent swabbed kicks, it is important to ensure that: •

The mud rheology is conditioned prior to tripping out

•

The tripping speed is controlled below the maximum allowable speed

•

The correct tripping procedures are followed

The equivalent circulating density (ECD) is relatively high when drilling a high angle well. This means a greater bottom-hole pressure reduction when circulation stops. Therefore it is important to flow-check the well prior to making a connection or tripping to ensure that the well is stable without the ECD effect. 2.

WELL SHUT-IN AND GAS KICK MIGRATION Use hard (fast) shut-in method to shut in the well upon detecting a kick to minimise the kick volume. Studies showed that the potential water-hammer effect associated with the hard shut-in is negligible. When a kick occurs in a high angle or horizontal hole section, the shut-in drillpipe pressure (SIDPP) will be close or equal to the shut-in casing pressure (SICP). This is because the kick only causes a small or no hydrostatic pressure reduction in the annulus. Zero shut-in pressures (SIDPP and SICP) do not mean there is no kick. Together with a positive pit gain, this may indicate that the kick is still in the horizontal hole section which may be caused by swabbing or improper hole fillup on trips. The conventional method, which determines the influx density/type (gas/water/oil) based on pit gain, SIDPP and SICP, can not be applied in a high angle or horizontal well. There is no simple alternative method for field applications. However, a gas influx can be recognised by the continuous increase in the casing pressure due to gas expansion above the horizontal hole section, which may be caused by gas migration during shut-in or by mud circulation. During the well shut-in period, the free gas usually migrates up the annulus if the angle is below 90°. Experiments showed that, for a mud with PV=10 cP and YP=6 lbf/100sqft, the gas migrates at about 10,000, 9500 and 7500ft/hr at vertical, 50° and 80°, respectively. The migration rate will be lower if the mud has a higher yield stress or gel. Do not calculate the migration rate based on the increase in SICP, as it often seriously underpredicts the migration rate. Gas does not migrate if: •

The hole angle is 90° or higher;

•

The gas is dissolved in the OBM; or

•

The gas is trapped as small bubbles in mud by its high gel strength


SUBJECT: 3.


Section

:

0402/GEN

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:

0 (05/96)

Page

:

2 of 2

WELL CONTROL IN HIGH ANGLE OR HORIZONTAL WELLS

WELL KILLING OPERATIONS The advantages of the wait-and-weight method over the driller’s method are less important in a high angle or horizontal well. This is because the weighted mud will not reduce the surface and casing shoe pressures until it has passed the high angle or horizontal hole section. By then the gas influx may have entered into the casing or been circulated out of the well. Do not wait for the mud being weighted up. Start to circulate using the driller’s method once a kick is detected; change over to the wait-and-weight method once the kill weight mud is ready (circulate and weight method). This will minimise the time of dealing with the kick and reduce the risks of stuck pipe and other hole problems. When pumping down the kill weight mud, use the kick sheet designed for high angle wells to work out the standpipe pressure schedule. Do not use the kill sheet designed for vertical wells, as it will result in excessive high well pressures and the possible consequence of fracturing the formation. During circulating out a gas kick, the free gas will slip through and travel faster than the mud, even in a horizontal hole section. Studies showed that the slip velocity is in the range of 60 to 180ft/min, depending upon the mud rheology and hole angle etc. Therefore the gas kick may arrive at surface much earlier than the mud.

4.

FREE GAS KICKS IN INVERTED (>90°) HOLE SECTION If a gas kick occurs when drilling an inverted hole section, the free gas will be trapped at the bottom of the hole when circulation stops. Similar scenario may also occur in washouts or undulations of a horizontal hole section. Studies showed that the free gas will remain being trapped unless the annular mud velocity exceeds about 100ft/min, which is higher than that at a commonly used SCR during well killing operations. Therefore special well killing techniques may have to be considered. The trapped gas may be flushed out by gradually increasing the SCR to a corresponding annular velocity of about 100 to 150ft/min for a short period of time (say 1/4 of bottom-up maximum). Then reduce to a normal SCR and proceed using a conventional well killing technique (driller’s or wait-andweight). Depending on the kick volume and the length of the hole section, the procedures may have to be repeated in order to remove the trapped gas completely. So prior to drilling the hole section, the pump pressure at an SCR corresponding to 100 to 150ft/min should be recorded. If the above technique fails to remove the trapped gas, consider bullheading the gas back into the formation. As the trapped gas should be near the kicking formation, bullheading is more likely to succeed in an inverted hole section.


BP EXPLORATION

SUBJECT: 1.

Section

:

0403/GEN

Rev.

:

0 (05/96)

Page

:

1 of 1

WELL CONTROL WHILST LOGGING

PREPARATION Hold a pre-logging safety meeting prior to commencing logging operations on the well in question and include in the discussion the shut-in procedure with wireline in the hole. The formal posted procedure should state that whenever pipe is out of the hole, the blind/shear rams should be closed if the well kicks, however, this action may not be totally appropriate if we have logging cable in the hole/across the stack. Below is a procedure which outlines the actions with wireline in the hole/across the stack if a well control scenario exists.

2.

PROCEDURE WHILST LOGGING ACROSS THE RESERVOIR/OPEN HOLE The well must be monitored at all times whilst preparing to log, logging and rigging down, and the action on detecting flow from the well is as follows: Note: Be aware that during running in with wireline, a very slight flow may be observed, this being the wireline displacement. (1) Advise logging contractor personnel to stop the winch. (2) Open HCR valve. (3) Close annular preventer – advise Toolpusher/BP Rep, who will then evaluate (in consultation with Onshore Team if time permits), the appropriate course of action. Note: This action will depend on a number of factors, eg rate of flow, pressures, logging tool position in hole. (4) Monitor well pressures and the closure effectiveness of the annular. (5) The decision may then be taken to use blind/shear rams in order to effect a well kill by bullheading (or to seal the wellbore).

3.

Note: (1)

Should it be necessary to close the blind/shear rams on the wire then, if possible, an attempt must be made to cut the wire to allow it to fall downhole prior to closing in the blind/shear rams. Again, there may be a scenario whereby the wire is being lifted out of the hole, in which case immediate closure of the blind/shear rams is required. It is the responsibility of the BP Rep to make this decision.

(2)

Prior to making any cut on the wire, ensure that the wire above the cut is clamped and tied off to avoid snaking of the surface after being cut.

(3)

All key personnel are to be made aware of the procedures and duties are to be assigned.

FURTHER RECOMMENDATIONS (1) A formal procedure of the above is to be made and posted on the rig. (2) Ensure that a risk assessment is carried out in relation to the above as it may capture some items that have been missed. (3) Ensure that the logging contractor is included in any assessments and that he is happy with the procedure.


SUBJECT:


Section

:

0405/GEN

Rev.

:

1 (3/95)

Page

:

1 of 1

LIMITED KICK TOLERANCE

1.

For full details of how to determine the Limited Kick Tolerance, refer to the BP Well Control Manual. The subject of limited kick is also addressed within the Casing Design Manual, a portion of which is repeated as Section 2005/GEN of these Guidelines for Drilling Operations Manual (Section A3.4).

2.

The Limited Kick Tolerance is sensitive to changes in: a) b) c)

Fracture pressure. Mud weight. Formation pressure.

When one or more of these parameters changes, the Limited Kick Tolerance must be recalculated. 3.

Calculate Limited Kick Tolerance for the hole section based on the actual leak-off at the casing shoe.

4.

The Limited Kick Tolerance should be recalculated for the midnight depth and for the hole section TD.

5.

Report the Limited Kick Tolerance values in the daily DEAP report, together with the appropriate depth and mud weight. Also ensure that the mud loggers are informed of these figures.

6.

When calculating the Limited Kick Tolerance, the pore pressure should be assumed equal to the mud weight in the hole.

BP EXPLORATION


Section

:

0410/GEN

Rev.

:

0 (7/90)

Page

:

1 of 2

SHALLOW GAS PROCEDURES

1.1

When the shallow seismic survey over a well location indicates the presence of seismic anomalies, and it is not practical to re-site the rig position, then the following procedures MUST BE FOLLOWED.

1.2

A 12 1/4” pilot hole will be drilled in open water to below the lowermost anomaly (refer to Section 1060/EXP).

Note: Anomalies will be penetrated only during the hours of daylight and in reasonable weather conditions. 1.3

The following shallow gas precautions will be taken in order to minimise the risk to the rig and personnel: 1.

The rig will be moored up with enough chain left in the lockers to enable the rig to move 150 metres off location. The anchor winch operation must be checked prior to drilling the anomaly. In water depths of less than 100 metres, consideration will be given to attaching a supply boat to the rig; the requirement will be discussed and agreed with the Marine Superintendent.

2.

One vessel capable of towing should remain on location.

3.

A watch will be kept at the moonpool to observe for gas breaking out of the sea under the rig. The watch keeper should be provided with a radio with which to contact the control room and drillfloor. The 12 1/4” pilot hole will be drilled with the ROV in attendance to observe any gas breaking out at the seabed.

4.

The weather conditions and tidal state will be monitored at all times and a preferred direction for moving the rig off location determined.

5.

A minimum volume of 400 bbls of 1.3 SG kill mud will be available to pump in the event that it is necessary to attempt to dynamically kill a gas flow.

6.

A safety meeting will be held prior to spudding the pilot hole. All gas detectors and alarms will be tested. All hot work permits are to be withdrawn. All bulk lines and salt water supply lines must be checked and the mud and cementing systems pressure tested.

7.

The 12 1/4” pilot hole will be drilled with seawater and viscous slugs. A float without bleed hole will be included in the drilling assembly. Rates of penetration will be restricted to 8 metres/hour from within 15 metres of the anticipated top of an anomaly. Once the anomaly has been penetrated the ROP may be increased at the discretion of the Drilling Superintendent. Circulation rate should be high, of the order of 800 gallons/minute.

8.

At total depth the hole will be circulated clean and displaced to seawater. The pumps will be shut down and the hole observed for flow.

9.

If no flow is observed then the pilot hole should be displaced to 1.3 SG mud prior to continuing with operations on the well.

10. In the event that a shallow gas flow does occur, either after displacement to seawater or during drilling, then circulate at maximum flowrates with seawater whilst allowing the accumulation to deplete. If unable to control the depletion, then pump the 1.3 SG kill mud. The kill mud must be pumped at as high a rate as possible to dynamically kill the flow.

BP EXPLORATION


Section

:

0410/GEN

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:

0 (7/90)

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SHALLOW GAS PROCEDURES

11. During any trips the drillstring should be pumped out of the hole. Every effort must be made to prevent a gas influx through swabbing. In the event that a shallow gas flow does occur whilst tripping, then the appropriate procedure will depend on the depth out of hole and the rate of flow. If possible, run back in the hole to bottom and pump the 1.3 SG kill mud at as high a rate as possible in an attempt to dynamically kill the flow. 12. If at any time the gas flow is so severe as to threaten the safety of the rig, then the rig should be moved off location in such a direction as to take the rig out of any gas plume in the water and so that the wind will carry gas away from the rig.

BP EXPLORATION


Section

:

0413/SEM

Rev.

:

0 (3/91)

Page

:

1 of 1

SHALLOW GAS PROCEDURES (DEEPWATER IN DP MODE)

1.1

When a shallow seismic survey has not been carried out over a deepwater (> 300m) well location with a rig operating in DP mode, then the following procedures MUST BE FOLLOWED.

1.2

A 12 1/4” pilot hole will be drilled in open water to below the surface casing shoe depth.

1.3

The following shallow gas precautions will be taken in order to minimise the risk to the rig and personnel: 1.

The 12 1/4” pilot hole will be drilled with the ROV in attendance to observe any gas breaking out at the seabed.

2.

The weather conditions and tidal state will be monitored at all times and a preferred direction for moving the rig off location determined.

3.

A minimum volume of 400 bbls of 1.3 SG kill mud will be available to pump in the event that it is necessary to attempt to dynamically kill a gas flow.

4.

A safety meeting will be held prior to spudding the pilot hole. All gas detectors and alarms will be tested. All hot work permits are to be withdrawn. All bulk lines and salt water supply lines must be checked and the mud and cementing systems pressure tested.

5.

The 12 1/4” pilot hole will be drilled with seawater and viscous slugs. A float without bleed hole will be included in the drilling assembly. Circulation rate should be high, of the order of 800 gallons/minute.

6.

At total depth the hole will be circulated clean and displaced to seawater. The pumps will be shut down and the hole observed for flow.

7.

If no flow is observed then the pilot hole should be displaced to 1.3 SG mud prior to continuing with operations on the well.

8.

In the event that a shallow gas flow does occur, either after displacement to seawater or during drilling, then circulate at maximum flowrates with seawater whilst allowing the accumulation to deplete. If unable to control the depletion, then pump the 1.3 SG kill mud. The kill mud must be pumped at as high a rate as possible to dynamically kill the flow.

9.

During any trips the drillstring should be pumped out of the hole. Every effort must be made to prevent a gas influx through swabbing. In the event that a shallow gas flow does occur whilst tripping, then the appropriate procedure will depend on the depth out of hole and the rate of flow. If possible, run back in the hole to bottom and pump the 1.3 SG kill mud at as high a rate as possible in an attempt to dynamically kill the flow.

10. If at any time the gas flow is so severe as to threaten the safety of the rig, then the rig should be moved off location in such a direction as to position the rig upwind and clear of any gas breaking free at sea level.

BP EXPLORATION

DRILLING MANUAL

Section

:

0415/GEN

Rev.

:

0 (8/90)

Page

:

1 of 1

SUBJECT: THE EFFECT OF COLD WEATHER ON BOP STACKS AND CONTROL LINES 1.

GENERAL

1.1

In extremely cold weather conditions, it is possible that BOP control lines, choke and kill lines or cooling systems may become frozen. The lowest ambient temperature in the UK North Sea is -10 Celcius.

1.2

When BOP control lines freeze, it is because the fluid in the lines contains insufficient glycol to protect it against ambient temperatures.

1.3

Only fluid in the 1” line on subsea BOP stack systems can be displaced simply by cycling the functions. The fluid in control lines on surface stacks and pilot lines can only be displaced if the lines are broken at the stack or pod.

1.4

To ensure that the pilot lines contain glycol treated fluid, whenever the ambient temperature falls below freezing point, the pilot accumulator must be fed from a dedicated reservoir in which the glycol concentration is maintained throughout the year. If this is not possible, then the required glycol concentration should be maintained in the whole reservoir.

1.5

To ensure the correct additive concentration, the constituents should be mixed in a separate tank. The fluid in the reservoir should be agitated to prevent glycol settling out and the concentrations periodically checked.

1.6

The possibility of glycol settling out within the pilot lines with time must be investigated.

1.7

Suitable precautions should be taken to prevent damage to cooling systems when equipment is shut down in cold weather.

1.8

Significant ice and snow accretions are rare, however any accumulation should be monitored to ensure the vessel’s design criteria are not breached.

1.9

Hydraulic equipment in storage may be vulnerable if it is not fully drained or filled with a suitable fluid.

2.

POLICY The following is mandatory on all BP operated rigs on the UKCS unless written dispensation is obtained from the Drilling Operations Manager (Dyce). 1)

Mud shall be retained in the choke and kill lines and circulated every shift. If a water based mud is in use, the salinity shall be controlled to prevent freezing under prevailing conditions. If the rig is in deep water or using high mud weights, consideration should be given to displacing the choke and kill lines to water containing an anti-freeze agent.

2)

Control fluid in subsea BOP pilot lines shall be protected against freezing above -10 Celsius throughout the year.

3)

Operating fluid in surface and subsea BOP lines shall be protected against freezing above -10 Celsius during the period 1st November - 30th April.

4)

If water based control fluid is used, the glycol concentration shall be confirmed by means of a hydrometer or refractometer each time the pilot lines are flushed through and once per day during the period 1st November - 30th April.

BP EXPLORATION


Section

:

0420/FIX

Rev.

:

5 (9/91)

Page

:

1 of 5

SURFACE BOP TESTING - GENERAL

1.

GENERAL

1.1

Refer to the BPX General Drilling Policy Document.

1.2

All wellhead BOP’s, valves, failsafes and risers shall be pressure tested from the direction they would be exposed to well pressure.

1.3

No personnel are to be in the vicinity of pressure testing operations or equipment. The Drilling Supervisor should ensure that ancillary BOP equipment, such as choke manifold, standpipe manifold, kelly cocks and stab-in valves, can be safely tested during normal rig operations, i.e. whilst POH or RIH.

1.4

On production platforms, consult individual Platform Safety Manuals with reference to “Permit to Work” requirements and precautions for pressure testing.

1.5

BOP Test Report and Accumulator Test Report Forms are to be completed after each test, and a copy sent to the Drilling Office (refer to page 5).

1.6

If installed, the diverter function is to be witnessed, and opening times should be recorded against the annular closing time on the BOP Test Report Form.

1.7

The Drilling Supervisor will witness the integrity of the tests and operation of all equipment.

2.

TEST PRESSURES

2.1

All well control equipment, except annular BOP’s, is to be pressure tested to the lowest of the following criteria: a) b) c) d)

Maximum anticipated wellhead pressure, based on the casing design data included in the drilling programme. 80% of casing burst pressure. Wellhead rated working pressure. BOP rated working pressure.

N.B. Equipment not in direct contact with the well may be tested to its rated working pressure if required. 2.2

The annular preventer must only be closed when pipe is in the hole and must never be tested to more than 70% of the manufacturers rated working pressure.

2.3

If a retrievable packer is set to test the BOPs, the test pressure must not exceed 80% of casing burst pressure.

3.

FREQUENCY AND TEST DURATIONS

3.1

The BOP test frequency will be: a) b) c) d) e) f)

Prior to installation of the BOP stack, on the test stump where applicable or after installation if no test stump is available. Every 14 days thereafter. Following any BOP repair. Following the reinstallation of the stack after wellhead spool installation. Following the breaking of any pressure seal, e.g. ram change. Within 7 days of the commencement of perforating or well testing operations.

N.B. BOP must always be function tested after installation.

BP EXPLORATION


Section

:

0420/FIX

Rev.

:

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Page

:

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Each test shall consist of two parts: a) b)

A 5 minute, 300 psi low pressure test. A 10 minute, rated pressure test.

4.

TEST PROCEDURES

4.1

Where possible all tests are to be done with clean water. When displacing BOP and manifolds from mud to water, the minimum amounts must be used to minimise contamination and losses.

4.2

Before filling the stack with water or installing pipe through rams, perform a full function test. (Do not allow rams or annular to close fully.)

4.3

Before the test can begin, the test line must be pressure tested to the highest planned pressure of the BOP test.

4.4

Unless otherwise stated in the drilling programme, all BOP tests will be in two parts: a) b)

4.5

A wellhead test using a cup type tester. A BOP test using a plug type tester.

When using a standard cup type tester: a) b) c) d)

The strength of the drillpipe and support equipment must be checked to ensure that they are adequate for the loads induced by the test. The annular preventer would normally be closed around the pipe. The drillpipe must NOT be supported by slips in the rotary table. Reduce the annular manifold closing pressure to 500 psi, to allow the pipe to slip through the element once the pressure has been applied. For maximum closing pressures see manufacturers’ specifications.

4.6

When using the cup tester to test pack-offs, ensure the casing pack-off test port and the wellhead annulus valve are open, in order to check for leakage.

4.7

When testing with plug type testers, side outlets below the seal face MUST BE LEFT OPEN to ensure stack test pressures do not pressure the wellbore and any leakage past the test plug is detected. Any valves or kelly cocks run below test plugs must previously have been tested and run closed.

4.8

In drilling condition wellhead side outlets will be dressed as follows: a)

b)

Outlets exposed to the wellbore: Active Outlet:

2 off fully rated valves plus Weco Union crossover. Both valves closed at all times apart from periods of wellhead/BOP testing.

Non-Active Outlet:

Fully rated VR plug plus fully rated cap flange or hubbed cap c/w needle valve.

Outlets in casing/casing annuli: Active Outlet:

Fully rated gate valve, blind flange and needle valve.

Non-Active Outlet:

Fully rated VR plug plus fully rated cap flange or hubbed cap c/w needle valve.

Note: No component - valve, needle valve, flange, VRP, cap flange/protector or crossover - may be installed on any wellhead outlet unless it has a working pressure rating at least equivalent to the spool it is being installled on.

BP EXPLORATION


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:

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4.9

When running test plugs through the wellhead, ensure all tiedown bolts/wear bushing lock bolts are retracted and all placking/gland nuts are tight. Check the stand-off measurement for these lockdowns. When test plugs are landed off in the wellhead, check depth below rotary table is correct before testing.

4.10

Record the volume of fluid pumped for each test, the closing/opening times of all functions and accumulator volume pumped for all BOP functions.

4.11

After a BOP test is complete, function test the remote operating panel(s). Do not allow preventers to close fully.

4.12

After each BOP test all rams are to be opened and the valves on the standpipe manifold and choke manifold set in the required positions for the following operations. Ensure all wellhead valves, needle valves and wellhead test ports are closed.

4.13

Blind rams are to be functioned once every trip.

4.14

The detailed test sequencing for stump and in-situ tests for each platform are in the appropriate Manual Section, and for Jack-Ups in Section 0440/JAK and 0441/JAK.

5.

TEST EQUIPMENT

5.1

Refer to manufacturers’ specifications for BOP operating pressures.

5.2

BOPs are to be tested utilising a plug type tester, ported drillpipe and an equipment arrangement as per the diagram in this Section.

5.3

A chart recorder showing the test pressure should be on the rig floor.

5.4

Two separate gauges, showing the test pressure, must be visible from the test pump to prevent overpressuring due to gauge failure or inaccuracy.

5.5

The condition of all sealing faces of BOP test plugs must be checked before and after they are run.

5.6

Cup type testers should be hollow bore type. When testing with cup type tools, no valves should be placed in the string below the cup tester.

5.7

Ensure all drillpipe used for testing is in good condition, smooth and is of the correct weight and grade to take the pressure testing loads.

5.8

All temporary high pressure lines must be fitted with cross coupling restraints and comply with platform regulations regarding their securing.

BP EXPLORATION


Section

:

0420/FIX

Rev.

:

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Page

:

4 of 5

SURFACE BOP TESTING - GENERAL GENERAL ARRANGEMENT FOR SURFACE BOP STACK TESTING 11 TEST LINE

10

12 3

9

KILL LINE

ANNULAR

ANNULAR

UPPER PIPE RAM

DP LANDING STRING

CHOKE LINE

UPPER PIPE RAM

BLIND RAM

BLIND RAM

6 5

4

1

LOWER PIPE RAM

No.

DESCRIPTION

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.

INNER CHOKE OUTER CHOKE 1st VALVE ON CHOKE MANIFOLD INNER KILL OUTER KILL KILL LINE N.R.V. PORTED SUB. PLUG TYPE TESTER TEST HEAD H.P. TEST TEE H.P. GATE VALVE MARTIN DECKER PRESSURE RECORDED C.H. SPOOL

2 LOWER PIPE RAM

7 8 13

OPEN

OPEN

2179/138

RIG

SUBJECT:

STACK SIZE x PRESSURE RATING

PLATFORM & JACK UP TEST SHEET DATE

OTHER EQUIPMENT TESTED

REMARKS

UPPER KELLY COCK

DATE LAST TEST

LOWER KELLY COCK

GRAY BOP

CASING SIZE

GRADE

WEIGHT

DEPTH

BURST

COLLAPSE

STAND PIPE MANIFOLD CEMENT UNIT

CONTRACTOR PLUG TESTER TEST A

TEST B

PRESSURE

TEST 1

PRESSURE

2

PRESSURE

C MAN

3

PRESSURE

PRESSURE

4 PRESSURE

VALVE CLOSED

5 PRESSURE

C MAN VALVE OPEN

KL

CL KL

CL KL

ANNULAR

CL KL

ANNULAR

ANNULAR

CL KL ANNULAR

CL KL ANNULAR

CL KL ANNULAR

CL

NON RETURN VALVE LOADED

ANNULAR NON RETURN VALVE EMPTY

UPPER RAM

UPPER RAM

UPPER RAM

UPPER RAM

UPPER RAM

UPPER RAM

UPPER RAM

BLIND RAM

BLIND RAM

BLIND RAM

BLIND RAM

BLIND RAM

BLIND RAM

BLIND RAM

LOWER RAM

LOWER RAM

LOWER RAM

LOWER RAM

LOWER RAM

LOWER RAM

LOWER RAM

CLOSED

OPEN

KL KILL LINE

CL CHOKE LINE

B.O.P. CONTROL POSITIONS ALTERNATE WEEKLY BETWEEN MAIN AND REMOTE POSITIONS

Section

:

:

5 (9/91)

0420/FIX

2179 /140

1 TEST PRESSURES AS PROGRAMMED 2 THISTLE KILL LINE BELOW LOWER RAMS 3 BEATRICE KILL LINE BELOW BLIND RAMS 4 THISTLE TUBING HEAD SPOOL SIDE OUTLET VALVES TESTED TO 5000PSI USING CUP TESTER / PORTED PLUG TESTER ASSEMBLY

Rev.

NOTES:

ANNULAR BOTTOM RAMS UPPER RAMS OUT CHOKE BLIND RAMS

5 of 5

SIGNATURE BP :

SEE STANDARD TESTING INSTRUCTIONS FOR HIGHER W/HEAD TEST PRESSURES

:

SIGNATURE CONTRACTOR

TIME MINS MINS MINS MINS MINS MINS

TIME TAKEN TO ACTIVATE UNIT AND VOLUME OF FLUID USED TO ACTIVATE MAIN PANEL REMOTE PANEL OPEN CLOSE OPEN CLOSE TIME VOLUME TIME VOLUME TIME VOLUME TIME VOLUME SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS

Page

B.O.P. PRESSURE ANNULAR PSI UPPER RAM PSI BLIND RAM PSI LOWER RAM PSI PSI PSI

NOTE:

BP EXPLORATION

CHOKE MANIFOLD

DRILLING MANUAL

R.T.E. WATER DEPTH


WELL NO.

BP EXPLORATION


Section

:

0420/SEM

Rev.

:

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:

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SUBSEA BOP TESTING - GENERAL

1.

GENERAL

1.1

Refer to the BPX General Drilling Policy Document.

1.2

All wellhead BOP’s, valves, failsafes and risers shall be pressure tested from the direction they would be exposed to well pressure.

1.3

Each rig is required to have a detailed pressure testing procedure which complies with BPPD Standard Health, Safety and Environment Regulations.

1.4

No personnel are to be in the vicinity of pressure testing operations or equipment. Notices should be posted and an announcement made on the public address system to warn all personnel of the test.

1.5

When test plugs are landed off in the wellhead, confirm the hang-off depth before commencing the test.

1.6

Record the volume of fluid pumped for each test, the closing/opening times of all functions and accumulator volume pumped for all BOP functions.

1.7

After a BOP test is complete, function test the remote operating panel(s). Do not allow preventers to close fully.

1.8

After each BOP test all rams are to be opened and the valves on the standpipe manifold and choke manifold set in the required positions for the next operation.

1.9

The Drilling Supervisor will witness the integrity of the tests and operation of all equipment.

2.

TEST PRESSURES

2.1

All well control equipment, except annular BOP’s and blind/shear rams is to be pressure tested to the lowest of the following criteria: a)

Maximum anticipated wellhead pressure, based on the casing design data included in the drilling programme.

b)

80% of casing burst pressure.

c)

Wellhead rated working pressure.

d)

BOP rated working pressure.

N.B. Equipment not in direct contact with the well may be tested to its rated working pressure if required. 2.2

The annular preventer must only be closed when pipe is in the hole and must never be tested to more than 70% of the manufacturer’s rated working pressure during routine testing.

2.3

Blind/shear rams need only be pressure tested during casing pressure tests after installation of the BOP stack on the wellhead.

2.4

If a retrievable packer is set to test the BOP’s, the test pressure must not exceed 80% of casing burst pressure.

3.

FREQUENCY AND TEST DURATIONS

3.1

The BOP test frequency will be: a)

Prior to installation of the BOP stack, on the test stump.

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b)

After installation of the BOP stack on the wellhead.

c)

Every 14 days thereafter.

d)

Following any BOP repair.

Each test shall consist of two parts: a)

A 5 minute, 300 psi low pressure test.

b)

A 10 minute, rated pressure test.

4.

TEST PROCEDURES

4.1

Where possible all tests are to be done with clean water. When displacing BOP and manifolds from mud to water, the minimum amounts must be used to minimise contamination and losses.

4.2

Before filling the stack with water or installing pipe through rams, perform a full function test. (Do not allow rams or annular to close fully.)

4.3

Before the test can begin, the test line must be pressure tested to the highest planned pressure of the BOP test.

4.4

When testing with plug type testers, any valves or kelly cocks run below test plugs must previously have been tested and run closed.

4.5

Whenever possible, routine testing is to be carried out with tools in the casing, and not when out of the hole.

4.6

Once the BOP is landed and latched, conduct an overpull test to 30,000 lbs. Using the test plug, pressure test the connector and one set of 5” pipe rams to the maximum test pressure that will be experienced by that connector during all subsequent operations. This pressure will be specified in the data sheet for the well in question.

Note: a)

Until the integrity of the connector seal is established, pressure testing volumes should be kept to a minimum to reduce the risk of washing out BOP/wellhead connectors.

b)

The connector should be monitored using the ROV/SSTV during the initial installation test. If a leak is detected pumping must cease immediately.

4.7

Once the BOP stack is landed and the connector seal confirmed, a full stack test will be performed.

4.8

When various ram sizes are installed, only the rams that may be required in the current hole section need to be pressure tested during routine tests.

4.9

When operations permit all rams should be function tested in rotation and the operating volumes recorded.

4.10

When performing fortnightly routine BOP tests, the control pods must be alternated with each test.

4.11

Test pressures are to be built-up in increments and stabilised at each stage prior to reaching the required test pressure.

Note: The BOP must be observed with the ROV/SSTV and the test plug landing string filled and monitored for leaks.

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4.12

All high pressure connections associated with the well control equipment are to be pressure tested upon the installation or re-installation of each connection.

4.13

All test pressures will be specified on the data sheets.

5.

TEST EQUIPMENT

5.1

Refer to manufacturers’ specifications for BOP operating pressures.

5.2

Two separate gauges, showing the test pressure, must be visible from the test pump to prevent overpressuring due to gauge failure or inaccuracy.

5.3

The condition of all sealing faces of BOP test plugs must be checked before and after they are run.

5.4

Ensure all drillpipe used for testing is in good condition, smooth and is of the correct weight and grade to take the pressure testing loads.

5.5

All temporary high pressure lines must be fitted with cross coupling restraints.

BP EXPLORATION


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:

0440/JAK

Rev.

:

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:

1 of 1

PRESSURE TESTING 21 1/4" BOP

For general pressure testing, refer to Section 0420/FIX. 1.0

The 21 1/4” stack may be used as: 1. 2.

A diverter system. A fully closing BOP system.

1.1

If used as a diverter system, the BOP will be tested to 500 psi only. If used as a fully closing BOP system, the test pressure will be advised in the Drilling Programme.

1.2

The test assembly to consist of: 2 stands of 5” HWDP below test plug. Test plug. Ported sub above the test plug. 5” DP to surface. Circulating head c/w HP tee connected to the pressure recorder and shut-off valve.

1.3

Prior to running test assembly: 1.

Ensure hanger/wear bushing lock screws are fully retracted (check stand-off measurement).

2.

Ensure lock screw gland nuts are fully tightened.

3.

Open side outlet valves on CH housing and drain stack.

4.

Fill 20” casing to side outlet level.

5.

Inspect seals on test plug.

1.4

Run and land test plug. Record landing height.

1.5

Pump through test string and fill wellhead with water. Ensure no returns from CH housing outlets.

1.6

Close the annular preventer, note closing time and operating pressure. Compare operating pressure with manufacturer’s recommended pressure for the relevant test pressure and pipe size.

1.7

If BOP is to be used as a fully closing system, flush the kill and choke lines to water. Close the first valves on the standpipe and choke manifold to exposed pressure.

1.8

Pressure up through the ported sub in 500 psi stages to the test pressure. 1.

If BOP is to be used as a diverter only, test to be against diverter spool outlet valves.

2.

If BOP is to be fully closing, test against choke manifold first valve and standpipe manifold first valve. Repeat tests against side outlet spools.

1.9

Open BOP. Record opening time.

1.10

Pull test assembly and close CH housing side outlet valves.

1.11

Make up drilling assembly and RIH to above top of cement.

1.12

Test casing to 500 psi.

1.13

Before drilling out, ensure that choke manifold valves are returned to correct configuration.

BP EXPLORATION


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:

0441/JAK

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:

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For general pressure testing, refer to Section 0420/FIX. 1.0

All tests will be done in two stages: 1. 2.

1.1

Cup Type Tester run into the casing stub. Plug Type Tester run into CH Spool.

The Cup Type Tester Routine 1.

Prior to running check the tester: a)

Mandrel inner “O” rings in good condition.

b)

Packer is correct for casing size and weight.

c)

The mandrel packer sealing area is free from corrosion.

d)

Condition of pack-off element.

2.

Run ± two stands of HWDP below the tester. With a new pack-off element additional weight may have to be used to ensure it enters the casing stub.

3.

a)

Ensure all wear bushing locking bolts are fully withdrawn (check stand-off measurement).

b)

Ensure all locking bolt gland nuts are fully tightened.

4.

5.

Run the Cup Type Tester on 5” S-135 DP. a)

Check the tool joint seal areas are in good condition.

b)

Check the Cup Type Tester is fully entered into the casing stub but is not within close proximity to a casing collar.

Open the CH Spool active side outlet valves below the relevant casing hanger. a)

Ensure the outlet is not plugged, e.g. VR plug left in place.

b)

Ensure the casing annulus is fully to the side outlet level.

6.

Fill the DP running string with water.

7.

Ensure the string is supported by elevators and travelling blocks, NEVER by slips in the rotary. Considerable tension can be produced in the running string, either by the test pressure or by inadvertent overpressuring. Slips can produce crushing of the DP.

8.

9.

Pre-calculate the probable maximum tension. a)

Ensure all lifting equipment is capable of safely supporting the load, i.e. elevator, links, blockline capacity.

b)

Check the dead man anchor gap is correct and clear of foreign material.

Close the annular preventer, pipe movement under pressure loading can damage the ram packers. a)

Record the closing time.

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b)

Check the annular operating pressure is as per the manufacturer’s recommendations for the relevant pipe size and test pressure.

c)

Flush through the BOP and choke manifold.

d)

Ensure the Martin Decker pressure recorder is rigged up on the choke manifold.

e)

Close the most direct valve to the choke line.

f)

Close the outside side outlet valves on the CH Spool above the casing stub.

10. Pressure up in 500 psi stages through the kill line and against the choke manifold. Ensure driller is holding the drawworks brake. He then has the opportunity to relieve any accidental overpressuring by lowering the tester. 11. Test the annular as indicated in Section 0420/FIX. 12. Observe for leaks. a)

Tester element leak will give continuous returns from the DP.

b)

Casing annulus leak will give returns from lower CH Spool side outlets.

13. Close inside valves of CH Spool, open outside valves as per Test B, page 5. 14. After the annular is proved competent, bleed off the kill line pressure and check the kill line NRV is preventing serious flow. 15. To bleed off pressures ensure an adjustable choke is closed behind the choke manifold valve to be opened. Open the valve quickly to minimise washing of the seat. Bleed down the pressure across the choke. 16. Open the annular preventer. Record opening time. 17. Pull the Cup Type Tester carefully through the stack and bell nipple. 1.2

The Plug Tester Routine 1.

2.

Prior to running check the tester. a)

Seal element in good condition.

b)

Correct size tester for CH Spool.

c)

Plug tester fitted in spool prior to spool installation.

d)

If tester has a through bore ensure a pre-tested closed kelly cock is run below the tester.

e)

On plug testers ensure cap bolts are not tight as this partially activates the seal elements causing incorrect test plug landing and results in frequent seal failure.

Below the tester run sufficient weight, to ensure plug fully lands in the CH Spool.

BP EXPLORATION


4.

Section

:

0441/JAK

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a) Ensure all wear bushing locking bolts are fully withdrawn (check stand-off measurement). b)

Ensure all locking bolt gland nuts are fully tightened.

c)

If not already done, circulate stack to water.

d)

Ensure the test tee, mobile pressure recorder and test shut-off valve have been tested to the test pressure required.

The test assembly above the Plug Tester: a)

A 4 1/2” IF pin x box sub with a through bore and a 1/2” NPT threaded side port.

b)

DP to surface, the burst pressure of which to be minimum 1.1 times the test pressure.

c)

Ensure connection above the ported sub is hand tight only.

Mark the string below the Plug Tester at a point that corresponds to CH Spool side outlet when the plug is landed. Full landing can then be checked. 5.

Run the plug tester and land. Ensure the depth below the rotary table is correct. Open the CH Spool side outlet and check that the position of the mark on the plug tester corresponds correctly.

6.

Make up the test head on the DP running string. a)

Open the first valve on the choke manifold. Fill stack with water.

b)

Close the top pipe rams around the DP and record closing time.

c)

Fill the DP with water.

d)

Make up test tee, pressure recorder and test valve to the test head. Preflush the test line and connect.

e)

Open the first valve on the choke manifold and flush through DP, BOP and choke line.

f)

Test as follows: Refer to test sheet on page 5.

7.

Ensure choke manifold has been pretested to the maximum required test pressure.

8.

Test 1 Ensure kill line open and kill line NRV unseated. Close the first valve (at end of choke line) on the choke manifold. Close inside valve on kill line.

9.

Pressure through the DP, below the rams and against the closed valves.

10. When test pressure is on, close the test line shut-off valve at the DP test head. There is no need to bleed off behind the shut-off valve. Compare the mobile pressure recorder and test pump gauges. 11. Inspect wellhead, rams and choke line for leaks.

BP EXPLORATION


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a)

If flanges are leaking, bleed off pressure and retighten.

b)

Leaks from CH Spool outlet indicate a leaking test plug seal or damaged CH Spool landing area.

c)

If leaks are detected from any lock bolt gland packings, bleed off pressure and retighten.

12. After completion of test, open shut-off valve and bleed off pressure at the test pump/cement unit. 13. Test 2 Reseat the kill line NRV and open inside kill line valve. Close HCR and open the first choke manifold valve. Ensure kill line vented/open on standpipe manifold. Repeat 9 through 12. 14. Test 3 Ensure kill line NRV is removed or lifted off its seat. Close outer stack mounted kill line valve. Close inner stack mounted manual choke line valve. Open HCR choke line valve. Repeat 9 through 12. 15. Test 4 Open upper pipe rams. Record time. Close lower pipe rams. Record time. Repeat 9 through 12. 16. Test 5 Open the outer stack mounted manual choke line valve. Open lower pipe rams. Record opening time. Rig down the test head etc. Back out running string leaving the plug tester set. Install the remote pressure recorder on the choke manifold. Rig up to pump through the choke line. Close blind rams. Record closing time. Close inner stack mounted kill line valve. Pressure test through the choke line. Bleed off pressures at test pump. Open blind rams. Record time. 17. Screw back into the plug tester and carefully retrieve tester through the stack. 18. Inspect the plug tester and prepare for storage. 19. Test the lower and upper kelly cocks from below to maximum 5000 psi whilst: a)

Performing accumulator test.

b)

Function testing the remote BOP operating panel.

20. When the kelly cock test is complete, install the gray valve below the lower kelly cock and test from below to 5000 psi.

RIG

SUBJECT:

STACK SIZE x PRESSURE RATING

PLATFORM & JACK UP TEST SHEET DATE

OTHER EQUIPMENT TESTED

REMARKS

WELL NO.

DATE LAST TEST

LOWER KELLY COCK

GRAY BOP

CASING SIZE

GRADE

WEIGHT

DEPTH

BURST

COLLAPSE

STAND PIPE MANIFOLD CEMENT UNIT

CONTRACTOR CUP TESTER TEST A

PLUG TESTER TEST B

PRESSURE

TEST 1

PRESSURE

2

PRESSURE

C MAN

C MAN

3

PRESSURE

PRESSURE

4 PRESSURE

VALVE CLOSED

5 PRESSURE

C MAN VALVE OPEN

KL

CL KL

CL KL

ANNULAR

CL KL

ANNULAR

ANNULAR

CL KL ANNULAR

CL KL ANNULAR

CL KL ANNULAR

CL

NON RETURN VALVE LOADED

ANNULAR NON RETURN VALVE EMPTY

UPPER RAM

UPPER RAM

UPPER RAM

UPPER RAM

UPPER RAM

UPPER RAM

UPPER RAM

BLIND RAM

BLIND RAM

BLIND RAM

BLIND RAM

BLIND RAM

BLIND RAM

BLIND RAM

LOWER RAM

LOWER RAM

LOWER RAM

LOWER RAM

LOWER RAM

LOWER RAM

LOWER RAM

CLOSED

OPEN

KL KILL LINE

CL CHOKE LINE

B.O.P. CONTROL POSITIONS ALTERNATE WEEKLY BETWEEN MAIN AND REMOTE POSITIONS

0441/JAK

2179 /150

:

ANNULAR BOTTOM RAMS UPPER RAMS OUT CHOKE BLIND RAMS

Section

VOLUME GALLS GALLS GALLS GALLS GALLS GALLS GALLS

0 (7/90)

TIME SECS SECS SECS SECS SECS SECS SECS

:

1 TEST PRESSURES AS PROGRAMMED

VOLUME GALLS GALLS GALLS GALLS GALLS GALLS GALLS

Rev.

NOTES:

TIME SECS SECS SECS SECS SECS SECS SECS

5 of 5

SIGNATURE BP :

SEE STANDARD TESTING INSTRUCTIONS FOR HIGHER W/HEAD TEST PRESSURES

:

SIGNATURE CONTRACTOR

TIME MINS MINS MINS MINS MINS MINS

TIME TAKEN TO ACTIVATE UNIT AND VOLUME OF FLUID USED TO ACTIVATE REMOTE PANEL CLOSE OPEN

MAIN PANEL OPEN CLOSE TIME VOLUME TIME VOLUME SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS SECS GALLS

Page

B.O.P. PRESSURE ANNULAR PSI UPPER RAM PSI BLIND RAM PSI LOWER RAM PSI PSI PSI

NOTE:

BP EXPLORATION

CHOKE MANIFOLD

DRILLING MANUAL

R.T.E. WATER DEPTH


UPPER KELLY COCK



Index Prefixes 0000


1000

Drilling

2000

Casing and Tubing

3000

Cementing

4000

Drilling Fluids

5000


6000


7000

Well Evaluation

8000






Section

Description

1000

DRILLING

1000/GEN

Drilling - General

1010/GEN

Depth Referencing

1020/GEN

BP Pipe Tally Procedure

1050/JAK

Well Establishment - Dril-Quip 3 Well Spacer Template

1060/SEM

Well Establishment - Running TGB

1070/SEM

Well Establishment - 12.1/4" Pilot Hole

1100/JAK

Drilling 36" Hole - Jack-Ups

1100/SEM

Drilling 36" Hole - Semi-Submersibles

1110/FIX

Conductor Installation - Run/Drill/Run/Cement

1130/FIX

Conductor Installation - Drill/Drive

1200/FIX

Drilling Surface Hole - Multi-Well Installations

1200/SEM

Drilling 26" Hole - Semi-Submersibles

1280/GEN

Underreaming in Top Hole

1300/GEN

Drilling Vertical 17.1/2" Hole

1310/GEN

Drilling Deviated 17.1/2" Hole

1320/JAK

Drilling Deviated 17.1/2" Hole Using Spacer Template

1350/GEN

Drilling 12.1/4" Hole

1400/GEN

Drilling 8.1/4" Hole


SUBJECT:


1450/GEN

Drilling 6" Hole

1500/GEN

Drilling Casing Flotation Equipment with PDC Bits

1630/GEN

Mud Motors

1640/GEN

Mud Motors Used with MWD Tools

1660/GEN

Rebel Tools

1700/GEN

Turbodrilling Procedures

1750/GEN

Sidetracking Procedures

1800/GEN

Suspension and Abandonment Procedures

1850/SEM

Wellhead Severance


SUBJECT:


1160/CLY

Drilling Top Hole & Running Conductor Clyde

1160/MAG

Drilling Top Hole & Running Conductor Magnus

1160/THI

Drilling Top Hole & Running Conductor Thistle

1160/MIL

Drilling Top Hole & Running Conductor Miller

1160/BRU

Drilling Top Hole & Running Conductor Bruce

1160/AME

Top Hole & Conductor - Amethyst

1160/HAR

Drilling Top Hole, Running Conductor and Cementing Harding

1210/FOR

Drilling 24" Hole Forties

1210/WYF

Drilling 24" Hole Wytch Farm

1220/BRU

Drilling 24" Hole Bruce

1310/AME

Drilling 17.1/2" Surface Hole - Amethyst

1310/WYF

Drilling Deviated 17.1/2" Hole Section Wytch Farm

1350/AME

Drilling 12.1/4" Hole - Amethyst

1350/WYF

Drilling Deviated 12.1/4" Hole Section Wytch Farm

1400/AME

Drilling 8.1.2" Hole - Amethyst

1400/WYF

Drilling Deviated 8.1/2" Hole Wytch Farm

NOTE: Sections highlighted in bold are those sections which have been modified (or inserted for the first time) in the most recent amendment to this Guidelines for Drilling Operations. Within each such section, the newly modified parts are identified by the bold black marker line on the right side of the text. A brief resume of the changes is provided at the end of this MST section. Sections underlined are those items which are available within this version of Acrobat.

BP EXPLORATION


Section

:

1000/GEN

Rev.

:

5 (11/90)

Page

:

1 of 5

DRILLING GENERAL

THE EQUIPMENT 1.

All downhole tools to be visually inspected by the BP Drilling Supervisor prior to running in the hole, i.e. thread condition, seal areas, jet size and bit type.

2.

Ensure the Drilling Contractor and Service Company maintain records of equipment usage and inspections and records are available on the rig, i.e. block line ton miles, DP, DC and jar rotating hours, and pump hours.

3.

The dimensions of any item run in the hole are to be recorded and fishing tools are to be available on board to catch all sizes. DP and DC connections are often overlooked, these should be checked on deck and sorted so a single over shot grapple size will catch all DP used to a known point in the string.

4.

Items used continously in the hole to be checked periodically on trips, i.e. DP and DC connections.

5.

Pressure control equipment to be function tested daily and pressure tested every 14 days.

6.

When 13.5/8” BOP’s in use: any line/outlet exposed to well pressure must have a double valve arrangement.

7.

All mud volume monitoring equipment, i.e. flo-show and PVT, to be checked at various rates/volumes prior to drilling out casing and twice daily thereafter to ensure measurements indicated are correct and alarms are functioning.

8.

Ensure all gas detection equipment and alarms are functioning.

9.

Ensure all rig floor gauges, recorders and alarms are functioning.

10. Ensure the solids control system is serviced/cleaned immediately upon shutdown. 11. Ensure mud pumps and mud system are personally inspected by the Drilling Contractor Toolpusher on a daily basis. 12. The rig maintenance staff should have records of all scheduled maintenance. The Chief Engineer must personally make a daily inspection of major equipment and keep the BP Drilling Supervisor informed on work pending. 13. A Crown-o-matic or equivalent safety brake will be installed on the drawworks and be operational at all times whilst drilling and tripping. (It may occasionally be disconnected for short periods of time whilst handling BHAs). 14. Only drill pipe with either: a)

No hard banding.

b)

Smooth grained, fine particle, flush ground hard banding may be used.

15. Only “fit for purpose” drill pipe must be used (as defined in the latest edition of API RP7G). 16. Drill pipe must be NDT inspected at least every three wells drilled, or 12,000 metres drilled whichever is the later. Bottom hole assembly components should be NDT inspected regularly on Category A wells. This is usually prior to each well. 17. No BHAs may be strapped or welded. 18. Inspection of drilling lifting equipment must be performed on all wells at five monthly intervals according to the BP colour code system.

BP EXPLORATION


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:

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:

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Page

:

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DRILLING GENERAL

19. Any drilling elevators in use should be subjected to 6 monthly inspections using 100% MPI (wet mag) and a certificate of fitness issued as per BP Drilling Inspection Procedure No. 9 (Elevators). 20. Rotary tongs of a rating higher than normal break-out torque must be available on wells which experience high drilling torque. 21. The following safety equipment must be on the Drilling Unit at all times and be fully functional: a)

Full-opening inside BOP counterbalanced appropriate.

b)

Surface installed NRV (i.e. Gray type).

c)

Crossovers to allow the installation of a) and b) into any type of connection to be used in the drill string, tubing or completion string.

d)

Drop-in-subs and darts (e.g. Hydril type) are to be available for each assembly run.

22. A trip tank must be available and be complete with a mechanically operated indicator of the trip tank level, visible from the Driller’s position. 23. Continuous monitoring and recording of the following parameters must be available on the drilling site for any wells: Active pit volume. Mud weight in. Mud weight out. Total gas (in percentage) at the header box. H2S (in ppm) - Alarm. Weight on bit. Hookload. Rotary torque. Rotary speed. Standpipe pressure. Rate of penetration. Pump SPM. Flowline monitor. The mud logging unit on any well must be capable of direct communication with the rig floor at all times. 24. Kick detection equipment must be operational at all times. 25. The following minimum kick detection equipment is required to be operational: Active pit volume monitors. Gas detection at header box. ROP recorder. Mud weight in. Mud weight out. Trip tank with a system for accurately monitoring returns during tripping. 2.

DRILLING OPERATIONS 1.

The Drilling Supervisor must ensure he gives the Drilling Contractor written instructions prior to drilling any section. These instructions must include: a)

The drilling parameters, e.g. WOB and maximum penetration rate.

BP EXPLORATION

DRILLING MANUAL SUBJECT: b) 2.

3.

Section

:

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:

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:

3 of 5

DRILLING GENERAL Contingency operations if a known problem could be encountered, e.g. losses, connection overpull, etc.

The Drilling Contractor is to be given written instructions prior to any trip out of the hole. These instructions to include: a)

Sequence of operation, i.e. flow check, drop survey.

b)

Maximum allowed overpull and procedures required if tight hole is encountered (refer to Section 6000/GEN).

c)

Preparation of equipment for following operations, e.g. prepare bit.

d)

Special instructions, e.g. check for swabbing.

The successful drilling of any section of hole will depend to a large extent upon the personnel on board noticing the problem with equipment or hole conditions prior to it developing to a serious level and taking action appropriately, e.g. increasing levels of connection overpulls, slow deterioration of mud properties, increasing levels of background gas, etc. In all situations the BP Drilling Supervisor must ensure that he is informed immediately of any deviation from normal routine which threatens the continuity of the operation, safety or overall cost.

4.

The efficiency of a rig will depend upon a high degree of organising and equipment preparation by the Drilling Supervisor.

5.

Ensure rig personnel are familiar with equipment and standard drilling practices, i.e. a)

Perform a D5 well kill drill prior to drilling out the intermediate and production casing strings. This should never be carried out when open hole sections are exposed (refer to BP Well Control Manual, Volume I).

b)

Flow checks to be made prior to any trip out of the hole and again at the casing shoe if hydrocarbon bearing zones have been penetrated.

c)

Trip tank to be used on all trips.

Note: Drilling Supervisor will be present on the rig floor to observe the first 10 stands pulled on every trip out of the hole, and until such time as he is satisfied that the hole fill volume is correct. 6.

A trip sheet will be filled out by the Driller on every trip in and out of the hole.

7.

Any deviation from expected hole fill-up volumes must be investigated and resolved.

8.

Slow circulation rates must be taken at least: i) ii) iii) iv)

Once per tour. At a bit change. At a BHA change. When the mud weight is changed.

A minimum of two pump rates will be used. Pressures must be recorded using the gauge to be used during well kill operations. 9.

On floating drilling units, choke line pressure losses must be determined and recorded: i) ii)

Prior to drilling out casing. On any significant increase in mud weight.

BP EXPLORATION


Section

:

1000/GEN

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:

5 (11/90)

Page

:

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DRILLING GENERAL

10. On all wells the mud logging unit must be manned at all times, during drilling, testing, completion and workover operations. 11. Ensure at all times adequate weight material, chemicals and LCM are available on board for ongoing operations. A minimum of 100 tonnes of barytes and sufficient chemical is required on board if drilling is to continue. 12. Bore protectors must be installed in the wellhead during all drilling operations. The wellhead design should take this into account. Bore protectors should be inspected at regular intervals as determined by the Drilling Supervisor. 13. Daily meetings should be held between the Company Drilling Supervisor, Rig Geologist and contractor’s personnel to discuss topics including: i) The forward programme. ii) Equipment out of commission that may affect drilling operations. iii) Any other matter that may affect the ongoing operation or safety. 14. The time spent with pipe out of hole must be reduced to an absolute minimum. Whenever possible, operations such as routine BOP testing, repairs and slipping and cutting of blockline, should be undertaken with tools in the casing. 15. A minimum of one complete hole circulation is to be performed prior to pulling out of the hole after completing all well kills. 16. When a drop-in sub is used in the drill string, the dart should be checked to ensure that it will pass through the kelly cock, the full opening safety valve and all subs used in the string. The dart and the drop-in sub should be checked for compatibility. 17. Jars should be run when drilling 17 1/2” and smaller hole sizes. They should be run in the drill collars and be sized to the drill collars. 18. In fast drilling sections from 17 1/2” hole downwards, check trips should be considered every 300m. On exploration/appraisal wells, surveys will be taken on these trips. Surveys will always be taken on bit trips. 19. Consideration should be given to running a junk sub prior to drilling with diamond or PDC bits and coreheads. 20. Ensure that, at all stages during the drilling operation, the mud condition is appropriate to the task in hand; drilling, tripping, logging, casing or cementing. 21. Prior to entering a prognosed reservoir, or setting casing, a magnetic multishot may be required. This will be advised in the drilling programme. 22. While drilling critical hole sections: •

Keep the active mud system surface area as small as is practical to ease kick detection. Any reserve mud stocks in tanks should be positively isolated from the active system. Ensure that the gates on the trough are sealing properly.

•

Adequate reserve stock of mud should be held; the volume and weight of which will be determined by the nature of the next hole section.

•

Ensure all pit level systems and tank isolating valves are working correctly before drilling into possible gas-bearing zones.

BP EXPLORATION


3.

Section

:

1000/GEN

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:

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:

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DRILLING GENERAL

•

Keep all mud treatments and pit transfers to the absolute minimum at critical sections of the well. Ensure that the Driller and the Mud Logging Engineer are aware in advance of any changes to the system.

•

Crew safety meetings should discuss the problem of gas kicks, especially if oil based mud is in use, and emphasise the importance of early detection. Mud engineering and logging personnel should attend these meetings.

•

Possibilities of pipe sticking should be discussed and any concerns addressed.

WELL CONTROL It is the BP Drilling Supervisor’s responsibility to ensure that AT ALL TIMES a flowing well can be controlled. Well control must be discussed with the contractor toolpusher to ensure:

4.

1.

The BP Well Control Manual is understood and STRICTLY adhered to by all rig supervisory personnel.

2.

The rig and its ancillary equipment is competent and pre-tested to ensure a flowing well could be controlled.

3.

The well status and all operations are constantly reviewed to ensure well control is not impaired.

4.

That all relevant BOP Drills are conducted throughout drilling operations in accordance with the instructions included in the BP Well Control Manual.

DRILLING PROGRAMME The Drilling Manual gives guidance and procedures to be adopted for drilling wells on a section by section basis. Any additional information required to drill a particular well, or any deviations from this Manual, will be highlighted in the Drilling Programme for that well.

BP EXPLORATION


Section

:

1010/GEN

Rev.

:

0 (9/90)

Page

:

1 of 1

DEPTH REFERENCING

1.

DETERMINATION OF ROTARY TABLE TO SEABED ELEVATION

1.1

Accurate measurement of rotary table to seabed is necessary to establish a datum point.

1.2

Make up spud-in assembly and run in strapping the pipe. Perform a penetration test with 20,000 lbs weight. Record the distance between seabed and rotary table corrected to MEAN SEA LEVEL using the CURRENT tide tables issued from Drilling Office, Aberdeen. Record the drilling draft, water depth and mean sea level to rotary table elevation. Jump the ROV to confirm measurements.

1.3

If the current is strong, particularly in deep water, it will be necessary to wait on slack tide before confirming rotary table to seabed elevation. Extra drill collars may be required to overcome the effects of string bending caused by current action.

1.4

The bottom of the permanent guide base is run and cemented 1.0 metre from the seabed. Once established, the top of the 18 3/4” wellhead becomes the well reference point.

1.5

Once the permanent guide base is established and the guide wires are in use, paint a mark on each wire relative to a fixed point in the moonpool. Any change in the difference between the painted mark and the relative point can be used for depth correction to compensate for vessel draft and tide changes.

2.

DEPTH REFERENCING DURING DRILLING OPERATIONS

2.1

On semi-submersible units, land off the BOP stack and riser equipment. Run the BOP test plug assembly using a painted single to confirm ram spacings. This measurement is used to determine the space-out for the emergency hang-off tool.

2.2

On semi-submersible units, when running equipment which lands off in a specific position inside the wellhead, e.g. wear bushing, pack-off, test plug, etc., always use a painted single to confirm correct land-off.

BP EXPLORATION


Section

:

1020/GEN

Rev.

:

2 (11/89)

Page

:

1 of 2

BP PIPE TALLY PROCEDURE

1.1

A master drill pipe Tally book to be set out as per page 2 of this section.

1.2

Master drill pipe Tally book to be kept by the driller in the dog-house and updated throughout his shift.

1.3

Separate lists to be made for differing pipe grades in the hole simultaneously, i.e. S135 and Grade G.

1.4

Both the drill pipe single and stand columns to be totalled vertically and compared with the cumulative total.

1.5

When totals show no discrepancy, the column is to be initialled by the driller on shift.

1.6

The contractor rig superintendent/toolpusher will make a daily check and also initial the totals.

1.7

When drilling or reaming, connection depths will be written on the geolograph recorder at time of connection.

1.8

The Contract rig superintendent/toolpusher is to make physical check daily of the total drill pipe on board.

1.9

Drillpipe checks to be made at each trip before and after reaching casing depths.

1.10

The drilling assembly tally to be made in the same manner as the DP Tally.

1.11

Each individual assembly item to be noted, i.e. 15 HWDP - 472.50 is not acceptable.

BP EXPLORATION


Section

:

1020/GEN

Rev.

:

2 (11/89)

Page

:

2 of 2

BP PIPE TALLY PROCEDURE

TYPICAL LAYOUT OF TALLY SHEET 742.57 31.50 31.00 31.20 1

742.57

91.94

834.51

91.01

925.52

31.13 30.94 29.87 93.70

93.70

9

31.33 30.29 31.54 2

742.57

31.24 29.95 29.82 93.16

186.86

10

92.33

279.19

11

92.46

371.65

12

93.87

465.52

13

93.27

558.79

14

91.82

650.61

15

91.96

742.57

16

742.57

Initials

Total

30.25 31.21 30.87 3 30.34 31.45 30.67 4 31.17 31.27 31.43 5 30.87 31.15 31.25 6 29.90 30.67 31.25 7 29.97 30.82 31.17 8 Total

N.B.

742.57

Initials

Double check system for lengths, cumulative lengths and bit depth must be used.

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?@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? ?

BP EXPLORATION


Section

:

1050/JAK

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WELL ESTABLISHMENT - DRIL-QUIP 3 WELL SPACER TEMPLATE

The Dril-Quip three well spacer template is designed to be deployed from a cantilevered jack-up rig to space out two new wells at 90° to each other from an existing suspended well (Figure 1). The unit is run on HWDP using a “J” type running tool and landed on the existing 30” conductor Quick Jay box just above the mudline. Once orientated using surface readout gyro, the unit is locked in place hydraulically with three single acting hydraulic pistons that react on the 34” OD of the Quick Jay box. The pistons are activated via a manifold on the template by applying pressure down the drillpipe. This pressure is locked in at the manifold by means of two non-return valves when drillpipe pressure is released at surface. 1.

EQUIPMENT CHECK LIST The following equipment is required when running/retrieving the template:

Item

Dril-Quip Part No.

Temporary Abandonment Cap T A Cap Running Tool (4 1/2” IF Box) Three Well Spacer Template Template Running Tool (6 5/8” Reg Box) Ported Sub (6 5/8” Reg Pin/Box) UBHO Sub (6 5/8” Reg Pin/Box) X/O Sub (6 5/8” Reg Pin/4 1/2” IF Box) Split Centraliser for Drill String

852294-01 330012 852425-01 852348-01 852428-01 N/A N/A 852426-01

Surface Readout Gyro Equipment inc. wireline unit. ROV and appropriate tooling.

Note: In these procedures the use of an ROV is assumed as the template is designed to be ROV friendly. However, divers can be used in place of the ROV. 2.

EQUIPMENT PREPARATION

2.1

All running tools should be visually inspected for obvious damage. In particular check the “J” slots for any damage that may interfere with the smooth running of the “J” running system. Repair the slots if necessary.

2.2

The template itself should be thoroughly checked prior to running. Hydraulics: Visually inspect the three hydraulically operated gripper dogs located on the bottom OD of the template for any obvious damage. These gripper dogs lock the template to the OD of the 30” Quick Jay box connection on the 30” conductor when the template is run. Check all the hoses/connections on the gripper dog housings and the manifold. Actuate the gripper dogs hydraulically to ensure that they move out freely. Lubricate the mechanism, if necessary, with a quality grease. After checking the locking mechanisms retract each one to a fully open position, by opening the dump valve on the hydraulic manifold. Once the hydraulic pressure has been vented, each dog can be pushed back to the open position.

Note: The fitting on the supply side of the manifold should now be fitted with two non-return valves set at 300 psi cracking pressure. This is used to prevent hydrostatic pressure from prematurely activating the gripper dogs. Two valves are now run to provide back-up.


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“J” Lugs: Visually inspect the four jay lugs, located at the top of the template, for damage. These jay lugs are used by the template running tool to run the template. Be concerned with any damage that might interfere with the template running tool when it is made up to the jay lugs. Repair the jay lugs if necessary. 2.3

Check that the ROV has correct tooling for operating the dump valve on the template hydraulic manifold and for severing hydraulic hoses.

3.

RUNNING PROCEDURE

3.1

Skid the rig directly over the existing well.

3.2

Run the ROV to conduct a visual seabed survey within a 70m radius of the location.

3.3

Position the Three Well Spacer Template on deck so that the rig can subsequently skid back in and be directly above the template.

3.4

Make up the Temporary Abandonment Cap Running Tool to HWDP and RIH. “J” into the Temporary Abandonment Cap with right-hand rotation. (Stabbing over the cap may require ROV assistance.) Confirm proper engagement of the running tool. Pick up and recover the Temporary Abandonment Cap complete with any stinger below.

3.5

Make up the Template Running Tool Assembly as follows: Template Running Tool Ported Sub UBHO Sub X/O Sub As the OD of the Template Running Tool is 42” it is unlikely to pass through the rotary table so it should be transferred below the rig floor and then lifted back up through the rotary table until the slips can be set on the running tool. Make up to a stand of HWDP.

3.6

Skid the rig back inboard to position the rotary table directly above the template.

3.7

“J” the running tool onto the template. Make up the hydraulic hose connection from the template manifold to the 1/2” NPT port in the Ported Sub.

3.8

Pick up the template and set the slips on the running tool. Breakout the stand of HWDP and set the tool face orientation of the UBHO sub to line up with the arm on the template of the first well to be drilled. Record the weight of template.

3.9

Run the template on HWDP and locate over the existing Quick Jay box. Observe this operation with the ROV. (It may be necessary to wait on slack tide to conduct this operation.) Slack off the weight of the template on the Quick Jay box and set the slips.

3.10

Rig up the surface readout gyro and RIH to the UBHO sub. Rotate the template to the right until the desired orientation of the first well from the existing well is achieved. Lock the rotary table to avoid any movement of the template. Rig down surface readout gyro equipment.


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(Using the ROV line up its camera on an axis through the centre of the existing well and first well to be drilled and record the ROV gyro reading. Due to inaccuracies of this method it may be different to that recorded for surface readout gyro, but it will be useful later as a quick check reference.) 3.11

Make up the top drive/kelly/circulating sub and apply 2000 psi pressure to the HWDP to activate the locking dogs. With pressure maintained at surface apply 5000 lbs overpull to confirm the dogs have activated and are gripping the Quick Jay connector. Observe with the ROV for any upward movement. If no movement, slack off the 5000 lbs overpull and bleed off the 2000 psi at surface. The 2000 psi should still be locked downhole by the non-return valves at the hydraulic manifold. Apply 5000 lbs overpull and hold for 5 minutes. Observe with the ROV for any upward movement. If no movement slack off the 5000 lbs overpull.

3.12

Prior to releasing the running tool assembly line up the ROV as per procedure in 3.10 and compare the ROV gyro reading with that previously recorded for the ROV gyro. (If there is any doubt that the template may have moved since orientation, then a check surface readout gyro should be run.)

3.13

Using the ROV sever the hydraulic hose connection from the template to the Ported Sub. Unjay the running tool by slacking off and rotating to the right and pick straight up. POH and lay down the running tool.

3.14

Skid the rig directly over the first new well to be drilled and prepare to spud.

Note: A split centraliser must be used at all times when drilling the 36” hole to ensure it is maintained centrally with respect to the template guidecan. It is in two halves and must be bolted together at the Texas deck level behind the bit or other BHA items as appropriate. 4.

RETRIEVAL PROCEDURE

4.1

After completing operations on the last well drilled through the guidecan skid the rig directly over the original well that the template is locked onto.

Note: At some point the Texas deck will have to be recovered so that the template can be retrieved. The best time to do this may vary from rig to rig. 4.2

Make up the Template Running Tool and RIH on HWDP. It will be necessary to transfer the running tool below the rig floor and then lift it back up through the rotary table until the slips can be set and the HWDP made up.

4.3

“J” into the template with left-hand rotation (stabbing over the template may require ROV assistance). Confirm proper engagement of the running tool.

4.4

Using the ROV, open the 1/4 turn dump valve on the template hydraulic manifold to vent the pressure behind the locking dogs. (If unable to turn the dump valve, use the ROV to sever a hydraulic hose on the hydraulic system.)

4.5

The template should now be lifted clear of the original well and the two new wells drilled.


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Note: If additional wells are to be drilled immediately, the template can be rotated 90° either way and lowered back down on the original well with one of the guidecans going over one of the two new wells. This leaves the second guidecan vacant for a third new well to be drilled. Alternatively, the rig could be skidded directly over one of the two new wells before lowering the template to give further options for positioning a third new well. In either case, the template does not require the hydraulic dogs to be locked as the template is now orientated by two existing wells and is prevented from tilting by the tight tolerance and length of swallow of the central locking can over the Quick Jay connector. 4.6

Recover the template to below the rotary table and skid the rig inboard.

4.7

Lower the template onto the deck and release the running tool with right-hand rotation followed by a straight pick-up. Lay down the template running tool.

4.8

Skid the rig back out directly over the original well.

4.9

Make up the Temporary Abandonment Cap to the Temporary Abandonment Cap Running Tool and RIH on HWDP and stab into the Quick Jay box. (This operation may require ROV assistance.) Confirm the Temporary Abandonment Cap is landed correctly. Unjay from the cap with left-hand rotation and pick up.

4.10

POH and lay out the Temporary Abandonment Cap Running Tool.

COUNTERWEIGHT

ft

SPLIT GUIDE CENTRALISER

36" HOLE OPENER

175"

BULLSEYE 26" BIT

CONTROLS

EXISTING WELL

HYDRAULIC PISTONS (3) GUIDE POST

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190"

8

SUBJECT:

90°

FIGURE 1

ESTIMATED WEIGHT: 5 TONNES HYDRAULIC PISTONS ARE OPERATED USING DRILL PIPE PRESSURE

HWDP TO SURFACE X/O 6 5/8 " REG PIN/4 1/2 " IF BOX UBHO 6 5/8 " REG PIN/BOX LOCK SUB 6 5/8 " PIN/BOX

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WELL ESTABLISHMENT - RUNNING TGB

1.0

A Temporary Guide Base (TGB) will normally only be run in deep water.

1.1

Prior to moving the rig onto location site survey results will be available giving information on possible anchoring conditions, seabed slope and the general nature of the seabed to a depth of 30m. The rig will normally be positioned at a location where the seabed is clear of obvious debris and has a slope less than 1 degree.

1.2

The standard equipment is a Temporary Guide Base with J-slot running preparation. The base will have the following additional features: •

Eye hooks to allow guideline replacement with ROV.

•

Holes drilled in 4 faces for the attachment of ballast box extensions if required.

•

Two base plates for mounting bullseyes.

•

Base plate for sonar beacon.

•

7” OD guide for remedial annular cementation.

1.3

The TGB should be positioned on the moveable beams on the cellar deck while under tow or running anchors and the guidelines worked.

1.4

Attach the four guidelines with shackles ensuring the pins are wired secure. Paint the guidelines at 1m intervals for the first 4m above the TGB. This will assist in determining the proximity of the TGB when running BHA’s.

1.5

If required attach the 4 ballast box extensions. Attach 2 bullseyes.

1.6

The TGB must be additionally loaded to allow working tension of about 6000 lbs on each guidewire while running the spud assembly and a minimum seabed loading of about 6000 lbs to prevent the TGB lifting as the guidewires compensate.

1.7

Make up the J slot running tool to the TGB and to the drillpipe running string. Incorporate bumper subs in the string as required by rig heave. In deep water consideration should be given to tensile loads and to using a shrouded bumper sub to minimise the risk of bumper sub failure.

1.8

Lower the TGB to seabed maintaining slight tension on the guidewires to avoid fouling. Mark the drillstring while running to ensure that it does not rotate while making connections. Confirm orientation with ROV compass/gyro.

1.9

Prior to landing the TGB, launch the ROV to check that the seabed is clear of obstruction. (Alternatively, run the rigs SSTV camera.) If any obstruction is seen, move the rig as necessary on the anchors to avoid it.

1.10

Land the base on seabed and allow the bumper sub to be partly closed to afford heave compensation. Check the slope indicator (bullseye) readings - the maximum acceptable angle is 2 degrees. For larger angles the guidebase should be picked up and repositioned.

1.11

Mark the four guidelines in a horizontal plane above the cellar deck using a permanent fixture as a reference. Indications of the guidebase tilting or settling can then be observed immediately.

1.12

Release the R. tool from the TGB (chain tong) taking care not to rotate the base. Adjust the guideline tensions to give about 1500 lbs tension above guideline buoyed weight. Retrieve the running tool. Ensure that the landing string is not rotated to avoid whipping action.

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WELL ESTABLISHMENT - 12 1/4" PILOT HOLE

1.0

If there is a likelihood that shallow gas will be encountered, a 12 1/4” pilot hole will be drilled. Refer to Site Survey in well dossier and shallow gas procedures (Section 0410/EXP). The depth of the pilot hole will be specified prior to spud.

1.1

Run BHA to seabed as datum for sonar. Jump ROV and conduct a seabed survey using sonar within a 70m radius of the location.

1.2

Record the distance between the seabed and the rotary table. The following should be reported on the Daily Drilling Report and on the IADC report: Water Depth at Mean Sea Level (metres) Rotary Table Elevation (metres) Operating Draft for the reported rotary table elevation (metres)

1.3

If high currents are evident, wait on slack tide.

1.4

Spud 12 1/4” assembly and drill to TD following shallow gas procedures (Section 0410/EXP).

Notes: a)

Any seismic anomaly must be penetrated during daylight.

b)

Spud the well with low flowrates until 30m below the seabed. Then increase flowrates to 600 GPM.

c)

The hole will be drilled using seawater.

d)

A 10 - 20 bbl viscous pill should be pumped and displaced to seabed as required, but at a minimum of every connection.

e)

Take a Totco/Teledrift survey 30m below seabed, further Teledrift surveys should be taken every 200m. If hole angle is above 1 deg. then ream hole as necessary.

f)

A pit full of 1.3 SG mud should be mixed and ready to pump should shallow gas be encountered.

1.5

At pilot hole TD, observe pilot hole with ROV for any signs of gas. POOH.

1.6

If signs of gas are evident, follow shallow gas procedures (refer to Section 0410/EXP).

1.7

If no gas is encountered, move the rig and spud the well (refer to Section 1100/SEM).

Note: In some cases the Drilling Programme may require the 30” conductor to be set prior to drilling the pilot hole.

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DRILLING 36" HOLE

1.

PRE-SPUD OPERATIONS

1.1

Ensure that all drilling tools and equipment, as per the Equipment Check List on page 3, are on board, checked out and in a serviceable condition prior to spud.

1.2

Ensure that all fishing tools relevant to Drilling Operations on the 36” hole section are on board, checked out and in a serviceable condition (refer to Section 6200/GEN).

1.3

Ensure that casing running tools and operators are all on board prior to reaching the section TD.

1.4

Ensure that drillstring well control equipment is in a serviceable condition.

1.5

Check the ID of all downhole equipment for passage of a FPI tool and survey instrument fishing tools.

1.6

Ensure that all General Drilling Instructions, detailed in Section 1000/GEN, are in place and adhered to.

2.

DRILLING - GENERAL

2.1

Make up the recommended 36” spud BHA as follows: -

26” bit (IADC 1-1-1) 36” hole opener with soft - medium cutters (7 5/8” reg. conn.) Bit sub c/w float valve 1 x 9 1/2” OD drill collar 36” stabiliser 3 x 9 1/2” OD drill collar 7 5/8” reg. pin x 6 5/8” reg. box crossover 2 x 8” OD drill collars

Add 5” HWDP and a dart sub as drilling proceeds.

Notes: a)

The Tandem 26”/36” assembly is selected to prevent ledges.

b)

If the formation is too hard, or if surveys show a tendency to drift, the assembly may be changed to 17 1/2” bit, 26” HO and 36” HO, or 17 1/2” bit and 26” HO.

c)

The 26” bit/36” hole opener should have a flow area such that the flow is diverted 2/3 to the bit and 1/3 to the hole opener. The Dril-Quip split centraliser will be run only if a TGB is run using the Dril-Quip wellhead system.

d)

If required, the centraliser is run loose on the string to centralise the drillstring within the 38” ID template guide. After drilling one single drill collar, pull back and move the split guide centraliser to above the stabiliser.

2.2

Tag the seabed and record the distance between the seabed and the rotary table. ROV should monitor the running of the string. The following should be reported on the Daily Drilling and IADC reports: Water Depth at Mean Sea Level (metres) Air Gap (metres) Rotary Table Elevation (metres) Spud Can Penetration (metres)

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DRILLING 36" HOLE

2.3

In areas experiencing high tidal currents it is advisable to wait on slack tide to ensure no lateral movement of the BHA occurs.

2.4

Spud well and drill 36” hole to section TD (normally +/- 60m or four joints of conductor below seabed).

Notes: a)

The well should be spudded using low circulation rates. A pump rate of 250 GPM should be used, increasing by 100 GPM for every 10m drilled, until the bit is 30m below the seabed. The pump rate can then be increased to 1000 GPM.

b)

The hole is to be drilled using seawater.

c)

A viscous (100 sec) pill should be pumped and displaced to seabed prior to each connection being made.

d)

The RPM and WOB should be varied to minimise the shock loading placed on the kelly or top drive.

e)

Surveys should be taken at every connection below seabed (refer to Section 7000/EXP). Maximum angle should be 0.5 degree at the mudline, and 2 degrees at section TD. If angle exceeds 1 degree, attempt to reduce by reaming.

2.5

At hole section TD take a final survey as per Section 7000/EXP.

2.6

Displace the hole to 1.15 SG viscous pre-hydrated bentonite mud, and POH to seabed.

2.7

RIH and check for fill. Clean out hole if required.

2.8

Drop survey.

2.9

Re-displace the hole to 1.15 SG viscous pre-hydrated bentonite mud and POH.

2.10

Rig up to run 30” conductor (refer to Section 2100/JAK).

3.

EQUIPMENT CHECK LIST

Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

1 1 2 2 1 1 1 1 1 1 1 8 (min.) 4 (min.) 2 2 30 (min.) 3 1 set

36” H/O (soft-medium cutters) c/w nozzles and spare cutter (7 5/8” Reg box-pin). 26” H/O (soft-medium cutters) c/w nozzles and spare cutter (7 5/8” Reg box-pin). 26” bit c/w jets and bit breaker. 17 1/2” bit c/w jets and bit breaker. Dril-Quip split centraliser (47” OD x 10 3/4” ID) (if required). 36” string stabiliser. 26” string stabiliser. 17 1/2” string stabiliser. Bit sub c/w NRV. 9 1/2” UBHO sub (7 5/8” Reg) (if required). Totco ring (crows foot type). 9 1/2” steel drill collars (7 5/8” Reg conns). 8” steel drill collars (6 5/8” Reg conns). X/Over sub 7 5/8” Reg pin - 6 5/8” Reg box. X/Over sub 6 5/8” Reg pin - 4 1/2” IF box. 5” HWDP (4 1/2” IF conns). 9 1/2” DC lifting nipples. 9 1/2” DC slips/elevators.

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DRILLING MANUAL SUBJECT: 19 20 21 22 23 24 25 26 27 28

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DRILLING 36" HOLE 1 set 1 1 1 set 2 1 lot 1 set Set 1

8” DC slips/elevators. Drill collar safety clamp. Dart sub. Totco equipment and overshot. DP elevators. Dope (drill pipe/drill collar). Survey equipment as required. Conductor running equipment. Fishing Tools (refer to Section 6200/GEN). 36” string roller reamer (to be considered as an alternative to the string stabiliser).

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DRILLING 36" HOLE

1.

PRE-SPUD PREPARATIONS

1.1

Ensure that programme, dossier and wallcharts are received.

Note: If the shallow gas seismic indicate “bright spots”, then a 12 1/4” pilot hole will be drilled. Refer to Section 0410/EXP. 1.2

Confirm correct location of rig.

1.3

Ensure that all equipment for this hole and casing section is on board the rig, as per the Group Loading.

1.4

Inspect drill string components as necessary.

1.5

Confirm that the ROV is fully operational and that a seabed survey of 70m radius is undertaken prior to spudding.

1.6

Ensure that viscous mud for top hole section is mixed.

1.7

Ensure that a Pre-Spud Meeting is held with the Rig Contractor’s and all Service Company Supervisory staff that are on board.

2.

SPUDDING AND DRILLING 36” HOLE

2.1

Prepare the PGB in advance by installing the guideposts and Regan 0° - 5° Slope Indicators. Designate numbers to the guideposts and paint the corresponding number of stripes on each guidepost in black paint, with clockwise numbering from number one at port aft.

Note: Ensure all dimensions of the PGB and guideposts are taken and recorded in the well file and a copy sent to town. Also all dimensions of 30” housing to be recorded and checked against Dril-Quip drawings. Prior to making up the spud assembly, move the PGB to the moonpool and orientate it according to the numbered guide posts. Attach the guide wires.

Note: Ensure that 3 1/2” tubing can pass through the PGB if a top-up cement job is required. 2.2

Make up the specified 36” BHA and run in. A typical spud assembly would be: 26” bit - 36” hole opener - float valve - 9 1/2” Teledrift sub (bored out for float) - 36” stabiliser - 8 x 9 1/2” DC - X/O - 3 x 8” DC - X/O - HWDP.

Notes: a)

A non-ported float valve must be run at all times.

b)

If there is any possibility of hard drilling on rigs with a top drive, then a drilling shock sub should be considered.

2.3

Tag the seabed. Check and record the distance between the seabed and the rotary table, taking the tide and barge drift into account. Observe with ROV.

2.4

If strong currents are evident, wait on slack tide.

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DRILLING 36" HOLE

Drill 26”/36” hole to section TD in one pass.

Notes: a)

The 36” hole should be drilled using low fluid flowrates. A circulation rate of 250 GPM should be used, increasing by 100 GPM for every 10m drilled until the bit is 30m below the seabed. The circulation rate can then be increased to 1,000 GPM.

b)

The hole is to be drilled using seawater.

c)

A viscous (100 sec) pill should be pumped and displaced to seabed as required, but at a minimum prior to every connection.

d)

A Totco/Teledrift survey should be taken when at 30m below seabed. If the hole angle is less than 1 deg. then continue drilling to section TD. If the hole angle is greater than 1 deg. then take surveys every connection. Ream the hole as necessary.

e)

If the hole angle increases, consider stopping and using a 17 1/2”/26” drilling assembly.

f)

The maximum allowable angle on the PGB is 2 degrees.

g)

Average sump length is to be 1m.

2.6

At TD displace the hole to viscous mud of 1.15 SG unless specified otherwise and POH to seabed. Drop survey.

2.7

POH to seabed. Wait one hour (recover survey).

2.8

RIH and check for fill. Clean out hole if required.

2.9

Re-displace the hole to viscous mud of 1.15 SG and POH.

3.


Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

1 2 2 2 2 2 2 2 12 (min) 15 (min) 2 2 30 (min) 3 1 set 1 set 1 1 set 2

36” H/O c/w nozzles and spare cutter (7 5/8” Reg box-pin). 36” string stabilisers. 26” bit, centre jet type c/w jets (24/32) + bit breaker. 26” string stabilisers. 17 1/2” bit c/w jets and bit breaker. 17 1/2” string stabilisers. 9 1/2” Teledrift sub c/w NRV. Totco Ring (crows foot type). 9 1/2” steel drill collars (7 5/8” Reg conns). 8” steel drill collars (6 5/8” Reg conns). X/Over sub 7 5/8” Reg pin - 6 5/8” Reg box. X/Over sub 6 5/8” Reg pin - 4 1/2” IF box. 5” HWDP (4 1/2” IF conns). 9 1/2” DC lifting nipples. 9 1/2” DC slips/elevators. 8” DC slips/elevators. Drill collar safety clamp. Totco equipment and overshot. DP elevators.

BP EXPLORATION

DRILLING MANUAL SUBJECT: 20 21 22

DRILLING 36" HOLE Set

Dope (drill pipe/drill collar). Casing equipment. Fishing equipment (refer to Section 6200/GEN).

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CONDUCTOR INSTALLATION - RUN/DRILL/RUN/CEMENT

INTRODUCTION Run/Drill/Run/Cement is the most common technique for conductor installation, currently in use in BP Platform Drilling Operations. The technique involves the running of part of the conductor through the jacket guides and hanging it off in the lower welldeck. A pilot hole is then drilled to the conductor setting depth and under-reamed for the conductor. The conductor is then run to depth and cemented, as per normal surface casing.

2.

PROCEDURE (TYPICAL)

2.1

Preparation

2.2

Carry out general casing checks as per Section 2000/GEN.

2.3

Check correctly sized rotary bushings are installed, complete with conductor slips.

2.4

Position conductor spider and baseplate on BOP deck.

2.5

Prepare all conductor connectors, handling tools, make-up tools and power units.

2.6

5” drillpipe elevators to be used for pipe handling.

2.7

A stand of 5” HWDP to be used for land-off.

2.8

Rig up to run conductor.

2.9

Run conductor. Tag seabed.

2.10

Pull back 2 - 3m.

2.11

Hang off conductor in lower welldeck or BOP deck dependent on Platform. Lock spider slips and recover the running string.

2.12

Make up spud-in assembly. Whether or not the 36” hole is nudged or not will be dependent on individual well directional requirements.

2.13

Drill 171/2"/26” pilot hole to conductor setting depth + 3m.

2.14

Displace hole to viscous mud.

2.15

Survey. POH.

2.16

Underream 26” pilot hole to 36” (refer to Section 1280/GEN).

2.17

Displace hole to viscous mud.

2.18

POH. Exercise care when tripping underreamer tools through the conductor.

2.19

Rig up to run conductor.

2.20

Run conductor to setting depth. Check top joint datum at the wellhead.

2.21

Land top joint in hang-off spider. Set slips. Lock spider and recover the running string.

2.22

Cement conductor as per individual field instructions or as per Section 3100/DEV.

2.23

Recover cementing stinger.

2.24

Slack off conductor.

2.25

Nipple up riser/diverter.

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CONDUCTOR INSTALLATION - DRILL/DRIVE

INTRODUCTION Drill/Drive is the least common of the conductor installation techniques in use in BP Platform Drilling Operations. The technique has application in variable seabed conditions of alternating hard and soft bands, where driving would not suffice but drilling/cementing are not favoured due towashout problems. The conductor is run to the seabed as per Section 1110/PLA. A pilot hole is then drilled through the conductor. The conductor is piled into this pilot hole and the procedure repeated as necessary to achieve conductor setting depth. This General Procedure is based on 27” diameter 1 1/4” wall conductor, with 24” pilot hole. Wide variations are possible, including initial piling followed by drilling. Drill/Drive Conductor Operations, due to the large quantity of Pile Driving Equipment involved, tend to be done in batches.

2.

CONDUCTOR STRING AND INSTALLATION The conductor is the first string of pipe to connect the surface diverter equipment to the production well being drilled and is installed to such a depth below seabed that it provides a positive foundation to which all surface wellhead and BOP equipment is attached. The conductor is 27” outside diameter, 1 1/4” wall thickness, grade X-52 pipe supplied in 40 ft lengths connected together using Vetco SR-20 connectors which are welded to the ends of each length of pipe. Each connector located above seabed level is protected against water ingress by the installation of a protective sleeve. All conductor pipe above the seabed level is also protected with coal tar epoxy paint. Options exist of installing the conductor strings by the “Drill/Drive” technique which entails establishing an initial penetration in the seabed by piling, drilling a 24” hole beneath the conductor shoe to a depth just short of the TD, running the conductor to the bottom of the predrilled hole and then piling to final TD to secure a firm foundation for the conductors. Alternatively, conductors can be installed by a modified procedure which is designed to avoid lost circulation problems if encountered and to minimise hammer handling time. Thus, the conductor string is run until the seabed is tagged whereupon the conductor is pulled back approximately 2 metres and hung off in slips on the BOP deck. A 12 1/4” hole is drilled directionally to 3 metres short of TD. Then the hole is opened out to 24” using a 24” hole opener assembly. Finally, the conductor is run to bottom and driven to refusal to establish a final TD. The depths of the shoes of adjacent conductors are usually staggered to prevent possible washout problems during drilling of the next hole selection, and to optimise directional requirements. The sequence of installation can be arranged to that where possible adjacent conductors are installed with sufficient time between installations to allow formations affected by constant piling to “firm up” and thereby ease condition of the hole during the drilling phase.

3.

INSTALLATION PROCEDURE (TYPICAL)

3.1

Prepare the shoe joint (cut bevel as required).

3.2

Lay shoe joint in V-door, pin up. (The first 10 joints run in each string including the shoe joint should be unpainted joints.)

3.3

Pick up shoe joint on handling tool using drawworks.

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3.4

Set shoe joint in slips in rotary table. Install safety clamp and remove handling tool.

3.5

Using second handling tool, pick up next joint with drawworks, and make up to shoe joint using power clamp.

3.6

Pick up the string and run down to set slips below top pin. Ensure shoe goes through power slips on BOP deck. Install safety clamp.

3.7

Repeat steps 3.3 - 3.6 until the seabed has been tagged (approximately 9 joints). Run final joint on drillpipe and handling tool to avoid problems of having to break out connector. Pull back some 2 metres and hang the conductor string off in the slips on the BOP deck. Attach safety clamp.

3.8

Lay down handling tool.

3.9

Pick up the 12 1/4” pilot hole drilling assembly and RIH.

3.10

Run in to seabed and drill the 12 1/4” hole to 3 metres short of planned shoe TD. Close control directional drilling may be required to ensure optimum conductor orientation. Circulate high viscosity pills as required to ensure proper hole cleaning. Drilling parameters will be dictated by directional drilling constraints. In particular, flowrates must be kept to a minimum in order to avoid eroding the hole.

3.11

Circulate the hole clean and POOH. Lay back the pilot hole BHA and pick up the 24” hole opening assembly. RIH and open the hole to TD (refer to Section 1280/GEN). A minimum bullnose length of 2m is required to ensure correct tracking of the hole opener in the pilot hole.

3.12

Circulate hole clean, spot viscous mud in open hole. POOH.

3.13

Pick up hammer and short chaser joint.

3.14

Pull back conductor from BOP deck to rotary. Watch slips on BOP deck and watch connectors for hang-ups.

3.15

Pick up and connect two conductor joints at the drill floor using handling tool below hammer/chaser.

3.16

Release handling tool from top of conductor joint. Lay down handling tool using the attached tugger.

3.17

Lower hammer/chaser joint assembly until chaser is engaged in the top of the conductor. Make up the chaser joint to the conductor pin as for the handling tool.

3.18

Pick up the string from the slips, remove safety clamp. Lower the string. Ensure spider slips on the BOP deck are locked open.

3.19

Continue lowering/driving the conductor monitoring blow count at all times. It is predicted that the blow count may increase typically by 5 blow/ft per 10m increment of depth shallow, to 90 blows/ft at depth.

3.20

If the conductor can be driven to the bottom of the pilot hole with less than 190 blows/ft, it should be driven into virgin formation a minimum of 3m of until a blow count of approximately 250 blows/ft is reached.

3.21

Should the blow count rise significantly above 250 blows/ft prior to penetrating virgin formation by 3m, then a further clean-out trip may be needed with the 24” bit after releasing chaser joint from conductor and setting conductor in slips on the BOP deck.

3.22

Conductor is to be cut off a set height above the cellar deck. The cut-off joints are to be retrieved and laid out.

3.23

A clean-out trip should be made to the shoe.

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After the conductor strings have been run and cleaned out, they are to be surveyed as per Standard Surveying Instructions.

Pilot Hole 12 1/4” sealed bearing bit (no jets) 7 5/8” turbine c/w float 1 1/2° bent sub UBHO sub 8” DC’s

2.

:


The following BHA’s are recommended during the drilling phase: 1.

Section

Hole Opening Assembly 8” bullnose Short DC, minimum length 8 feet 24” hole opener 24” stabiliser 2 x 8” DC’s 24” stabiliser

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DRILLING SURFACE HOLE - MULTI-WELL INSTALLATIONS

INTRODUCTION Surface Hole is considered to be the first hole section drilled out of the conductor. This section will typically have a number of problems not normally associated with the other hole intervals: a)

If shallow gas is present in the area, it is most likely to occur in Surface Hole.

b)

Close well spacing and near-well proximities result in tight directional control requirements.

c)

Weak, unconsolidated or damaged surface sediments can cause hole cleaning problems or lost circulation, in surface hole sections.

As a result of these potential problems, Surface Hole is normally pilot drilled with a 17 1/2” or 14 3/4” assembly, with close directional control applied to avoid dogleg conditions. The section will be drilled with a Diverter System, as a minimum. After conductor cleanout and prior to drilling ahead, the conductor should be surveyed with Gyro Multishot. All survey requirements for this and subsequent hole sections will be as per the Standard Surveying Instructions. It is rare for Surface Hole to be drilled straight; the section is often “nudged” and in some cases directional kick-off is done in Surface Hole. If, when drilling the pilot hole or hole opening, there are indications of gas, then pump out of hole on all trips - if in doubt pump out. Where there is a possibility of shallow gas, an 8 1/2” pilot hole may be required and will be included in the Drilling Programme. A shallow gas contingency plan will be in place for each individual platform where appropriate. 2.

PRE-DRILLOUT OPERATIONS

2.1

Ensure that all Drilling Tools and equipment, as per Section equipment listings, are on board, checked out and in a serviceable condition prior to conductor drillout.

2.2

Ensure that all fishing tools, relevant to drilling operations on the Surface Hole Section, are on board, checked out and in a serviceable condition prior to conductor drillout.

2.3

Ensure all BOP, Diverter, and Drillstring Well Control Equipment is in a serviceable condition.

2.4

Complete rig-up of Diverter, Diverter Lines and BOP Stack if required. Complete function testing of same, from all BOP control positions. See Section 0420/FIX and relevant Platform Section.

2.5

Ensure that all General Drilling Instructions, detailed in Section 1000/GEN - Drilling General, are in place and adhered to.

2.6

Ensure that all relevant BOP Drills, in accordance with the guidelines listed in the BP Well Control Manual, are understood by all rig personnel and are implemented at the relevant stages of Surface Hole Drilling Operations.

2.7

Ensure that all solids control equipment is available and in a fully operational condition.

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3.

CONDUCTOR CLEANOUT

3.1

The conductor will require to be surveyed after cleanout and a tie-in point obtained.

3.2

If a steering tool is to be used at a later stage, have a working stand or side-entry sub prepared.

3.3

a)

30” Conductor/30” Riser/30” Diverter Make up slick 26” cleanout assembly: 26” BIT (3 x 28) - BS - 3 x 9 1/2” NMDC - XO - 3 x 8” DC XO - 9 x HWDP. Install Diverter Packer Element and function test. RIH. Drill Shoe Track using mud, circulating at maximum rate. Wash/ream to bottom of 36” Rathole. Circulate hole clean with 100 bbl High Vis Pill. POH. Survey 30” conductor as per Drilling Programme. Make up kick-off assembly.

b)

30” Conductor/21 1/4” Riser/21 1/4” Diverter/21 1/4” BOP Make up slick 17 1/2” cleanout assembly: 17 1/2” BIT - BS - 3 x 9 1/2” NMDC - XO - 3 x 8” DC XO - 9 x HWDP. RIH. Drill Shoe Track using mud, circulating at maximum rate. Wash/ream to bottom of 36” Rathole. Circulate hole clean with 100 bbl High Vis Pill. POH. Make up 26” underreamer cleanout assembly: 17 1/2” BIT - 17 1/2” SS - PONY - 26” UR - 3 x 9 1/2” NMDC - XO - 3 x 8” DC - XO - 9 x HWDP. RIH. Cleanout Shoe Track and Rathole, circulating at maximum rate (refer to Section 1280/GEN). Circulate hole clean with 100 bbl High Vis Pill. POH. Survey 30” conductor as per Drilling Programme. Make up kick-off assembly.

c)

26 1/2” Conductor/21 1/4” Riser/21 1/4” Diverter/21 1/4” BOP (Assumes 26 1/2” conductor is piled.) Make up 17 1/2” cleanout assembly: 17 1/2” BIT - 17 1/2” NBS - 2 x 9 1/2” NMDC - XO - 3 x 8” DC - XO - 24 x HWDP.

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RIH. Drill out 26 1/2” conductor, circulating at maximum rate. Wash/ream to conductor shoe depth. Circulate hole clean with 100 bbl High Vis Pill. POH. Make a check trip with a 24” underreamer, reaming from the mud line to the conductor shoe (refer to Section 1280/GEN). Circulate the hole clean with 100 bbl High Vis Pill. POH. Survey 26 1/2” conductor as per Drilling Programme. Make up drilling assembly. 4.

DRILLING

4.1

Make up pilot hole drilling assembly: The 26” hole is normally piloted with a 17 1/2” or 14 3/4” assembly. This section is normally nudged and close deviation control is necessary as high dogleg severity over this shallow section of the well could result in excessive casing wear and excess torque build-up. The 14 3/4” assembly will be used where tighter directional control is required. Option A This option should be used wherever there are tight tolerance restrictions in order to get the survey tool as close to the bit as possible. Drill pilot hole as follows: 17 1/2” bit c/w centre nozzle - 11 1/4” mud motor - bent sub - UBHO sub - 3 x 9 1/2” DC - 3 x 8” DC HWDP - dart sub. The pilot hole is drilled under directional control using SRG cluster shots as detailed in the Standard Surveying Instructions, the section can be drilled to casing point in this manner. Option B Drill pilot hole as follows: 17 1/2” bit c/w centre nozzle - 11 1/4” mud motor - bent sub - 10’ NMSDC - MWD - monel UBHO sub - 3 x 9 1/2” NMDC - 3 x 8” DC - HWDP - dart sub. The use of a 1 3/4° bent sub will ensure that adjustments are achieved quickly. If motor is fitted with a dump valve, this should be removed or plugged to prevent risk of backflow and possible plugging of the drillstring. Option C Drill pilot hole as follows:

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17 1/2” bit c/w centre nozzle - steerable motor - 9 1/2” NMSDC - 17” NM stab - 9 1/2” MWD - 9 1/2” NMUBHO - 17” NM stab - 2 x 9 1/2” NMDC - 3 x 9 1/2” DC - 3 x 8” DC - HWDP - dart sub. This option is similar to Option B but has the advantage of providing more control when in rotary mode over a bent sub-motor combination.

Note: In Options B & C - where applicable. Ensure bit nozzles are compatible with MWD, additional HWDP are used to increase rigidity. DO NOT use nozzle in MWD restrictor sleeve; only tungsten restrictor sub is necessary. Option D In certain circumstances and dependent on BOP configuration, this section can be drilled in one pass using a 26” bit beneath a motor and bent sub or a steerable motor. Directional control is limited and in general this option should not be attempted for long sections as bit life is limited. 4.2

The pilot hole is drilled under directional control, initially with minimal inclination the MWD can be used in “High-Side Mode” to obtain inclination and toolface. An orientating gyro, SRG or equivalent (Gyrodata), will be run every 30m to check azimuth and inclination. Once clear of magnetic interference, the MWD can be switched to “Magnetic Mode” to obtain both inclination and azimuth. The expected depth to be clear of magnetic interference will normally be stated in the drilling programme, this can be confirmed by obtaining 2 adjacent survey stations of MWD that are in agreement with the gyro survey results, after which only the MWD will be used.

4.3

Drill to required casing point keeping mud weight as per programme, using 50 bbl viscous pills as required. Flowrates should be controlled at 800 gpm initially to ensure oriented sections are not washed away in unconsolidated formations.

4.4

Control drilling rate if necessary so as not to overload annulus, bearing in mind circulation rate may be limited by flowrate through mud motor, otherwise pump at max. rate through this section to keep hole clean.

4.5

If a tangent section of hole is called for, and providing there is no magnetic influence from adjacent casing strings, this section may be drilled with an MWD tool as follows: 17 1/2” bit c/w centre nozzle - NB stab - c/w NRV - 9 1/2” NMSDC - 17 1/4” NM stab - MWD - 9 1/2” NMDC - NM stab - 9 1/2” NMDC - 3 x 9 1/2” DC - 3 x 8” DC - 12 HWDP - dart sub.

4.6

At TD, circulate 100 bbls Hivis pill around and circulate clean. Displace to viscous mud. POH and strap pipe out.

4.7

Open hole to 26”/24” using: 17 1/2”/14 3/4” bit (bullnose) - 17 1/2”/14 3/4” stab - short DC - 26” hole opener (underreamer) - bit sub c/w NRV - 2 x 9 1/2” DC - 26” (17 1/2”) stab - 1 x 9 1/2” NMDC - MWD - Totco - 2 x 9 1/2” NMDC - 3 x 8” DC - 12 HWDP - dart sub.

Note: a) Ensure nozzles are compatible with MWD. b) Refer to Section 1280/GEN.

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26” sump below 20” shoe to be limited to 5m max., this reduces the cuttings build-up in the sump and subsequent problems that result. 4.8

SRG or equivalent check surveys may be taken during hole opening operations, every ± 100m, dependent on anti-collision tolerances.

4.9

In the event of very tight tolerances, a high accuracy gyro will be run through DP where there is any doubt about borehole location.

4.10

Circulate hole clean at TD and sweep with viscous mud. Make wiper trip, circulate hole clean and spot viscous mud. POH and strap pipe.

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DRILLING 26" HOLE - SEMI-SUBMERSIBLES

1.

GENERAL

1.1

The 26” hole section will be drilled riserless unless: a)

It is a Government regulation to drill with a riser; or

b)

A mud system is required to drill the hole for surface casing; or

c)

Evaluation of the following factors indicates that it is safer to drill with a riser and diverter system: i) ii) iii) iv)

Water depth. Sea current magnitude and characteristics. Diverter/riser system design. Mooring system design.

The decision to drill with a riser will be taken by the Drilling Office. 1.2

If the shallow seismic survey indicates the potential for shallow gas, a 12 1/4” pilot hole will be drilled (refer to Section 0410/EXP).

2.


2.1

Ensure that all drilling tools and equipment, as per the Equipment Check List on page 4, are on board, checked out and in a serviceable condition prior to Casing Drillout. Ensure that the gyro survey equipment is, if required, available after cementing the casing but before drilling out the shoe.

2.2

Ensure that all fishing tools relevant to Drilling Operations on the 26” hole section are on board, checked out and in a serviceable condition prior to Casing Drillout (refer to Section 6200/GEN).

2.3

Ensure that casing running tools/operators are all on board prior to reaching the section TD.

2.4

Ensure that all drillstring well control equipment is in a serviceable condition.

2.5

If a riser is in use, ensure that the flex joint wear bushing is installed.

2.6


2.7

Prior to drilling out the conductor shoe, make up the 18 3/4” wellhead housing/running tool assembly to the 20” casing wellhead joint in the rotary table (refer to the Dril-Quip Manual and Section 2200/SEM). Make up the subsea launch mandrel to the bottom of the wellhead running assembly. A drill pipe pup joint may be installed between the running tool and the launch mandrel and cement plug if required. Lay the assembly down on the pipe deck, or rack back in the mast.

2.8


2.9

Ensure that all relevant BOP drills, in accordance with the guidelines listed in the BP Well Control Manual, are understood by all rig personnel and are implemented at the relevant stages of 26” Hole Drilling Operations.

3.

DRILLING 26” HOLE RISERLESS

3.1

Make up the specified BHA and RIH. As a precaution wash down to tag TOC. A typical 26” hole assembly would be: 26” bit - float sub (non-ported) Teledrift tool - Totco ring - 2 x 9 1/2” DC - 26” SS - 3 x 9 1/2” DC - X/O - 6 x 8” DC - X/O - 6 x HWDP - DS.

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Notes: a)

Paint bottom 3m of BHA white to aid observation of entry into 30” housing.

b)

Attach soft rope lines between the guidelines and BHA, approximately 3m above the bit. Ensure that the ropes run freely on the guidewires.

c)

Unlock the compensator and observe entry of the BHA into the 30” housing with the ROV/SSTV.

d)

A dart sub must be run when drilling below the conductor.

3.2

Drill out the conductor shoe with care to avoid damaging the cement job around the 30” shoe.

3.3

Clean out the rathole and drill 26” hole to TD with seawater, pumping 50 bbl viscous slugs every 10m, or as required.

Notes: a)

If shallow gas is present, follow the procedures detailed in Section 0410/EXP.

b)

Typical drilling parameters are: Circulation Rate WOB RPM ROP

: : : :

1200 gpm (once the BHA is clear of the conductor shoe). 10 - 20,000 lbs. 120. Limited to 30 m/hr.

c)

Take Teledrift surveys at regular intervals.

d)

Minimise the casing sump.

3.4

At section TD displace the hole to weighted viscous mud as specified in the drilling programme (normally 1.2 SG).

3.5

Drop the Totco survey barrel and POOH to the 30” shoe. Recover the survey barrel.

3.6

RIH and check for fill. Clean out if required and deepen sump if necessary. Re-displace the hole to mud of required weight as indicated in the drilling programme. POOH strapping the pipe.

Note: Carefully jet inside the 30” housing on the way out of the hole. 3.7

Observe the 30” housing with the ROV/SSTV for signs of gas.

4.

DRILLING 26” HOLE WITH RISER

4.1

It may be necessary to drill the 26” hole with mud in order to provide greater hole stability. In this case the 30” conductor will be set at a depth allowing full returns of the mud required to drill the section.

4.2

The programmed mud system in this case will normally be a bentonite/polymer system with the mud weight as low as possible (refer to Section 4120/GEN).

4.3

This hole section will be underreamed to 26” after drilling the required pilot hole.

4.4

Drill out the 30” shoe and clean out the sump with seawater using a pilot bit with 26” hole opener. Circulate a viscous pill to clean out the hole and displace to weighted bentonite mud. POOH.

4.5

Make up the pilot assembly and RIH. A typical pilot assembly would be:

BP EXPLORATION


Section

:

1200/SEM

Rev.

:

0 (8/90)

Page

:

3 of 4


Bit - float sub (non-ported) - Teledrift tool - Totco ring - 2 x 9 1/2” DC - SS - 3 x 9 1/2” DC - X/O - 6 x 8” DC - X/O - HWDP - DS.

Note: A dart sub must be run when drilling below the conductor. 4.6

Drill the pilot hole to TD with mud. Typical drilling parameters are: Circulation Rate : 1100 gpm. WOB : 0 - 10,000 lbs. RPM : 120.

Note: The two common problems encountered in drilling the pilot hole are: a)

An increase in mud weight in the annulus due to a build-up of drilled cuttings. This may cause losses.

b)

Shaker screen blinding due to large quantities of drilled cuttings or sand and the viscous nature of the mud. Some manufacturers supply sand screens for the shakers. If these are available, they should be on board prior to drilling the pilot hole.

To combat both of these problems, it may be necessary to limit penetration rate when drilling the pilot hole. Typically, penetration rate is limited to 30 m/hr and the hole circulated clean every 300m prior to taking a survey. When drilling long sand sections, the mud should be monitored closely for sand content to avoid equipment damage. 4.7

At TD circulate clean, drop a survey and POOH.

4.8

Make up and RIH the bit/26” underreamer assembly.

4.9

Underream the pilot hole using mud (refer to Section 1280/GEN).

Note: Ensure that the underreamer arms are fully opened before commencing underreaming. 4.10

At TD perform a wiper trip to the 30” shoe. RIH and displace the hole to weighted, viscous bentonite mud.

4.11

POOH to the 30” wellhead and circulate carefully the riser to seawater. Allow the riser contents to drop to sea level and observe for flow.

4.12

If the well is static, POOH.

4.13

Pull the riser.

4.14

Rig up and run the 20” casing.

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:

1200/SEM

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:

0 (8/90)

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Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27

1 2 2 2 2 2 2 2 12 (min.) 15 (min.) 2 2 30 (min.) 3 3 1 set 1 set 1 1 set 2 sets

28 29

2 Set

26” hole opener c/w jets and spare cutters. 26” bit, centre jet type c/w jets and breaker. 26” string stabilisers. 17 1/2” bit c/w jets and bit breaker. 17 1/2” string stabilisers. Sub 7 5/8” Reg box - box (bored to take NRV). Float sub c/w NRV (7 5/8” Reg conns). Totco ring (crows foot type). 9 1/2” steel drill collars (7 5/8” Reg conn). 8” steel drill collars (6 5/8” Reg conn). X/Over 7 5/8” Reg pin - 6 5/8” Reg box. X/Over 6 5/8” Reg pin - 4 1/2” IF box. 5” HWDP (4 1/2” IF conns). 9 1/2” DC lifting nipple. 8” DC lifting nipple. 9 1/2” DC slips/elevators. 8” DC slips/elevators. DC safety clamp. Totco equipment and overshot. DP elevators/slips. Dope for DP and DC. Grey inside BOP 4 1/2” IF conn. Circ. head 4 1/2” IF pin - 2” Lo torque valve. Hydril kelly cock (4 1/2” IF conn). Casing equipment. Teledrift tools c/w surface equipment. 26” underreamers (if drilling pilot hole) c/w spare arms. Hydril drop-in dart sub (4 1/2” IF conns). Fishing tools (refer to Section 6200/GEN).

1 1 1 2 2

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:

1280/GEN

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:

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UNDERREAMING IN TOP HOLE

1.

The following practices should be adopted when underreaming large top hole sections:

1.1

When underreaming with roller bearing cutters and controlled drilling or WOB cannot be maintained, reduce the RPM to between 50 - 80. This should avoid premature gauge wear on cutter cones and arm shirtails which could result in the loss of cones in a short period of time.

1.2

If the underreamer arms will not close due to drilled debris blocking the arm pockets, pump at the highest rate possible and at the same time rotate at high RPM. It may be possible to “bounce” the drill string off bottom to loosen the material.

1.3

Where very fast underreaming is possible, ensure enough RPM is used to prevent cutting a spiral hole at least 100 RPM is recommended.

1.4

When hole opening, the use of an expanding blade stabiliser may assist in maintaining vertical hole. Placing a stabilised pilot hole assembly below the underreamer may not guarantee vertical hole.

1.5

On making the initial underreamerr cut, rotate for at least 5 - 15 minutes at a reduced rate of 30 - 40 RPM and at full pump rate, prior to attempting to drill ahead. This should allow sufficient time for a full gauge initial cut to be made. The harder the formation, the longer the time required before drilling ahead.

1.6

After having underreamed about 3m, stop rotating, pick up the string with the pump still on, and lower the string attempting to tag the ledge that should have been cut. If the formation is firm enough and has not washed out, this will give an indication that the hole is being cut. If the formation is very soft or badly washed out, this procedure will not work.

BP EXPLORATION


Section

:

1300/GEN

Rev.

:

1 (12/91)

Page

:

1 of 5

DRILLING VERTICAL 17 1/2" HOLE

1.


1.1

Ensure that all drilling tools and equipment, as per the Equipment Check List on page 3, are on board, checked out and in a serviceable condition prior to Casing Drillout.

1.2

Ensure that all fishing tools relevant to Drilling Operations on the 17 1/2” hole section are on board, checked out and in a serviceable condition prior to Casing Drillout (refer to Section 6200/GEN).

1.3

Ensure that logging tools/operators and casing running tools/operators are all on board prior to reaching the section TD.

1.4

Ensure that BOP equipment and drillstring well control equipment is in a serviceable condition.

1.5

Complete wellhead pressure testing, and carry out a BOP test as per Sections 0420/FIX and 0420/SEM. Set wellhead wear bushing. On semi- submersible units, install the flex joint wear bushing.

1.6


1.7

On floating units, make up and stand back the Emergency Hang-Off Tool.

1.8

On floating units, prior to casing drillout, make up the 18 3/4” x 13 3/8” casing hanger to the running tool complete with pack-off and SSR plug mechanism (refer to Section 2300/SEM). Stand back in the derrick on HWDP.

1.9


1.10

Ensure that all relevant BOP drills, in accordance with the guidelines listed in the BP Well Control Manual, are understood by all rig personnel and are implemented at the relevant stages of 17 1/2” Hole Drilling Operations.

2.

DRILLING GENERAL

2.1

Make up 17 1/2” bit and assembly and RIH to +/- 20m above the plug/cement.

Notes: a)

A typical 17 1/2” straight hole assembly would be: 17 1/2” bit - Totco - NBS - 1 x 9 1/2” DC - 17 1/2” SS - 1 x 9 1/2” DC - 17 1/2” SS - 3 x 9 1/2” DC - 2 x 8” DC - Jars - 2 x 8” DC - 12 HWDP.

b)

Perform a D5 kick drill and record details on the IADC and Daily Drilling Reports.

c)

Be aware of the danger of the bit drilling through the centre of the plug, leaving the outer section to ride up above the bit. This may cause a hydraulic piston effect that can result in pumping the drillstring out of the hole.

2.2

Wash down as a precaution to tag TOC.

2.3

Prior to drilling out the cement and 20” shoe, test the casing to the lower of: i) ii)

2.4

Maximum anticipated wellhead pressure. 80% of casing burst.

Drill out to the shoe with seawater, pumping 50 bbl hi-vis slugs while drilling the cement. While drilling the shoe and 26” rathole, pump a 100 bbl hi-vis pill and displace to mud. If mud is OBM, pump a dye to observe the mud/seawater interphase.

BP EXPLORATION


Section

:

1300/GEN

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:

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2 of 5


2.5

Drill 3m of new hole. Circulate to condition the mud.

2.6

Carry out formation leak-off test as per Section 7100/GEN. Record the results in the well file and the Daily Drilling Report.

2.7

Calculate the Limited Kick Tolerance based on the formation leak-off test results. Kick tolerances should then be updated every day. Refer to Section 0405/GEN. Take SCR’s.

2.8

Drill ahead to section TD with wiper trips if hole conditions dictate. Surveys to be taken at least every 300m. Minimise casing sump at section TD.

2.9

Prior to POOH, ensure that the hole is in good condition and circulated clean.

2.10

At TD, flow check and drop a survey as specified.

Note: Ensure hole is in good condition before performing the survey. 3.

SECTION NOTES i)

Pump 50 bbl hi vis pills prior to making connections if hole cleaning dictates.

ii)

Maximise circulation rate to maintain annular velocity to optimise hole cleaning. Note: Account must be taken of the effect of ECD on weak formations.

iii)

Only run sufficient drill collars for the planned WOB.

iv)

On deep 17 1/2” sections it may be necessary to shorten the BHA length to minimise the pressure drop in order to maintain the required circulation rates.

v)

All surveying to be undertaken as per BP Standard Surveying Instructions.

vi)

Penetration rate should be limited to maximise hole cleaning. Refer to the 17 1/2” hole cleaning curves on pages 4 and 5. Good hole cleaning can be maintained by keeping YP at 30+ (but not less than 25).

vii)

WOB and RPM will be determined by the ROP limit.

viii)

If any major problems arise with the mud or solids control equipment, stop drilling and circulate until the problem is rectified.

ix)

Adhere to the hydraulics programme, particularly the maximum required pump rate. Never drill ahead with one pump; pull to the shoe and repair.

x)

If the hole packs off, attempt to work the pipe down in order to regain circulation before attempting to jar out.

xi)

It may be necessary to make a check trip before running casing. No wiper trip will be required if the hole condition is good.

xii)

A gyro survey will normally be required in the 13 3/8” casing after the first 12 1/4” bit run. Alternatively, for wells where the 13 3/8” casing is set deep, a magnetic multishot may be programmed in which case 9 1/2” monel drill collars will be run on the check trip assembly. The survey tool/operator should be on board prior to reaching the 17 1/2” TD.

BP EXPLORATION


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:

1300/GEN

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:

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3 of 5


4.


4.1

Vertical Wells

Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

Selection 2 3 2 2 2 12 (min.) 15 (min.) 2 2 30 3 3 1 set 1 set 1 1 set 2 sets 1 1 2 2 1 2 1 1 2 1 1 As required Set 2

17 1/2” bits c/w jets (selection) + breaker. 17 1/2” near bit stabilisers. 17 1/2” string stabilisers/gauge tool. Sub 7 5/8” reg box-box (bored to take NRV). Float sub c/w NRV (7 5/8” reg conns). Totco ring (crows foot type). 9 1/2” steel drill collars (7 5/8” reg conns). 8” steel drill collars (6 5/8” reg conns). X/over 7 5/8” reg pin - 6 5/8” reg box. X/over 6 5/8” reg pin - 4 1/2” IF box. 5” HWDP (4 1/2” IF conns). 9 1/2” DC lift nipples. 8” DC lift nipples. 9 1/2” DC slips/elevators. 8” DC slips/elevators. DC safety clamp. Totco equipment and overshot. DP elevators/slips. Gray inside BOP (4 1/2” IF conns). Circ. head 4 1/2” IF pin - 2” Lo torque valve. Hydril kelly cock (4 1/2” IF conn). 5” DP pup joints (1 x 1.5m and 1 x 3m). Dope for DP and DC. Junk sub (7 5/8” reg conns). Drilling jars. Circulating sub (7 5/8” reg conns). Casing equipment. 9 1/2” PONY DC. Mud savers (if OBM used). Dart sub c/w dart. MWD tool if required. 9 1/2” Monel drill collars (7 5/8” reg conns). Fishing tools (refer to Section 6200/GEN). 17 1/2” string roller reamers (to be considered as an alternative to the stabilisers).

BP EXPLORATION


Section

:

1300/GEN

Rev.

:

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:

4 of 5


EFFECTIVE VISCOSITY DETERMINATION

40

1. DRAW LINE FROM MUD YP THROUGH CUTTINGS SIZE TO INTERSECT LH PROJECTION LINE AT A*

PROJECTION LINE

PROJECTION LINE

50

PROCEDURE

CUTTINGS SIZE (in) 1 /4

2. DRAW LINE FROM A* THROUGH HOLE DIAMETER TO CROSS RH PROJECTION LINE AT B*

EFFECTIVE VISCOSITY (cP)

30

300

3. DRAW LINE FROM B* TO MUD PV

1

17 / 2

1

/2

20

200

121/ 4

100

1

8 /2

80

HOLE DIAMETER (in)

4. READ OFF EFFECTIVE VISCOSITY AT CROSS-OVER POINT

60

10

100 40 20

0

0

0

YIELD POINT (lb/100ft2 )

PLASTIC VISCOSITY (cP)

PROJECTION LINE

PROJECTION LINE

CUTTINGS SETTLING VELOCITY DETERMINATION

SETTLING VELOCITY (ft/min)

60 50 40

2.1

2.2 MUD SG

1.0 2.3

30 60

300

2.0

20

2.4

50

1.5

200

40 1.0 MUD SG

2.5 10 1 /4 " CUTTINGS

5. DRAW LINE FROM EFFECTIVE VISCOSITY THROUGH MUD SG TO INTERSECT LH PROJECTION LINE AT C*

30

6. DRAW LINE FROM CUTTINGS SG THROUGH MUD SG TO INTERSECT RH PROJECTION LINE AT D*

1.5

100 2.6 20

7. JOIN C* AND D*. READ OFF SLIP VELOCITY FOR APPROPRIATE CUTTINGS DIAMETER

1

/2 " CUTTINGS

0 EFFECTIVE VISCOSITY (cP)

2.0

2.7

CUTTINGS SG

8. CONTINUE TO NEXT FIGURE

2179 /164

BP EXPLORATION


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:

1300/GEN

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:

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:

5 of 5


171/2" VERTICAL HOLE CLEANING

CUTTINGS SLIP VELOCITY (ft/min) 40

60 50

30 20 10

PENETRATION RATE (m/h) 50

40

30

20

0

PIVOT POINT

10

140 100 80

60

50

40

30

20

ANNULAR VELOCITY (ft/min)

PROCEDURE (CONT.) 9. DRAW LINE FROM CUTTINGS SLIP VELOCITY THROUGH PIVOT POINT TO CROSS PENETRATION RATE LINES. 10. FOR APPROPRIATE ROP, READ MINIMUM ANNULAR VELOCITY.

2179 /165

BP EXPLORATION


Section

:

1310/GEN

Rev.

:

3 (12/91)

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:

1 of 6

DRILLING DEVIATED 17 1/2" HOLE

1.


1.1


1.2


1.3


1.4


1.5

Complete wellhead pressure testing, and carry out a BOP test as per Sections 0420/FIX and 0420/SEM. Set wellhead wear bushing. On semi-submersible units, install the flex joint wear bushing.

1.6


1.7

On floating units, make up and stand back the emergency hang-off tool.

1.8

On floating units, prior to casing drillout, make up the 18 3/4” x 13 3/8” casing hanger to the running tool complete with pack-off and SSR plug mechanism (refer to Section 2300/SEM). Stand back in the derrick on HWDP.

1.9


1.10


2.

DRILLING GENERAL

2.1

MU 17 1/2” bit and assembly and RIH to +/- 20m above plug/cement.

Notes: a)

Wash down as a precaution to tag TOC.

b)

Perform a D5 kick drill and record details on the IADC and Daily Drilling Reports.

c)


2.2

Drill out shoe track to float shoe with seawater, if changing to OBM.

2.3

Drill out shoe and clean out sump with SW.

2.4

Pump 70 - 80 bbl of base oil or base oil spacer.

2.5

Displace to OBM circulating at highest possible rate.

2.6

Drill 3m of new hole.

2.7

Carry out formation leak-off test as per Section 7100/GEN. Record the results in the well file and the Daily Drilling Report.

BP EXPLORATION


Section

:

1310/GEN

Rev.

:

3 (12/91)

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:

2 of 6


Calculate the Limited Kick Tolerance based on the formation leak-off test results. Kick tolerances should then be updated every day. Refer to Section 0405/GEN. Take SCR’s.

2.9

If gyro multishot is required on the surface casing, this is to be performed before drilling ahead.

2.10

Drill ahead to section TD (13 3/8” shoe depth + 3m).

2.11

Main Build-Up Section The main kick-off is generally planned for this section with a build/turn to final inclination and azimuth followed by a tangent section to 13 3/8” setting depth. Depending upon the final azimuth and inclination of the 26” section, there are various options open in which to drill the 17 1/2” build-up section. a)

Mud Motor + MWD Drill kick-off section using MWD as a steering tool. Assembly: 17 1/2” bit - 11 1/4” mud motor - bent sub - 1 x 9 1/2” NMSDC - MWD - 2 x 9 1/2” NMDC - 1 x 8” DC - jar - 3 x 8” DC - 9 x HWDP.

b)

Steerable Motor Assembly There are two types of systems in use: i) ii)

Bent motor housing type. Double tilted U-joint housing (DTU).

Both systems are stabilised and can be used to drill tangent sections in addition to the build-up section. The advantage being the ability to make corrections in azimuth and inclination, but a full economic review should be made prior to running the system. A typical assembly would be: 17 1/2” bit c/w centre nozzle - steerable motor - 9 1/2” NMSDC - 17” NM stab - 9 1/2” MWD - 17” NM stab - 2 x 9 1/2” NMDC - 3 x 9 1/2” DC - 8” DC - jar - 3 x 8” DC - HWDP - dart sub. When using a steerable system, it is imperative to determine its directional characteristics in rotary mode, both inclination and azimuth. Where possible, once a main build section has been 3/4 completed, drill say 2 stands in rotary mode, having determined its characteristics continue the build-up taking account of the systems natural tendencies to negate making numerous small corrections. From experience it has been found that numerous small corrections over a section result in an increased torque build-up, which on shallower wells is less of a problem but can become critical on deep high step out wells. c)

Rotary Build Assembly 60 ft On completion of initial build-up using mud motor and bent sub, continue the build with the following assembly: 17 1/2” bit - 17 1/2” NB stab - 9 1/2” NMDC - MWD - 17 1/2” NM stab - 9 1/2” NMDC - 17 1/2” NM stab - 9 1/2” NMDC - 9 1/2” DC - stab - 1 x 9 1/2” DC - 8” DC - jar - 3 x 8” DC - 9 HWDP.

BP EXPLORATION

DRILLING MANUAL SUBJECT: d)

Section

:

1310/GEN

Rev.

:

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Page

:

3 of 6


Rotary Build Assembly 70 ft + If at the end of the 26” section there is ± 12° inclination and well is on final azimuth then the following assembly would normally be used to negate the use of a mud motor. 17 1/2” bit - 17 1/2” NB stab - 2 x 9 1/2” SNMDC - MWD - 9 1/2” NMDC - 17 1/2” NM stab - 1 x 9 1/2” NMDC - 17 1/2” NM stab - 1 x 9 1/2” DC - 8” DC - jar - 3 x 8” DC - 9 HWDP. It may be necessary if build rate becomes excessive to POH and shorten up to a 60 ft build assembly until required inclination is reached.

Note: If MWD tool is short, ensure pony MDC is installed to make up overall length to 30 ft. 2.12

Tangent Section The assembly is “locked up” in this section. 17 1/2” bit - 17 1/2” NB stab - 9 1/2” SNMDC - 17 1/2” NM stab - 1 x MWD - 9 1/2” NMDC - 17 1/2” NM stab - 1 x 9 1/2” NMDC - 17 1/2” NM stab - 1 x 9 1/2” DC - 8” DC - jar - 3 x 8” DC - 9 HWDP. Section Notes i)

Ream any motor drilled build-up sections on way in to bottom with tangent assembly or build assembly.

ii)

Pump hole cleaning pills prior to making connections if hole conditions dictate. In high angle wells combined lo-vis and high weighted pills may be considered.

iii)

Circulate at max. rate to maintain annular velocity for optimum hole cleaning, min. rate 1100 gpm. Account must be taken of the effect of ECD on weak formations.

iv)

Make wiper trips every 180m unless advised differently from office.

v)

Where overpulls occur on trips, wipe out mechanically but if they persist on subsequent trips increase mud weight up to a maximum as advised in the Drilling Programme or from drilling office.

vi)

Always circulate min. 140% bottoms up prior to any trips. Based on a 1/2” cutting, it has been calculated you need 140% annular volume to get bottoms up - check shakers clean.

vii)

Position jars in the string with 3 x 8” DC above. Keep neutral point whilst drilling away from the jars.

viii)

If MWD goes down in tangent section, drill ahead with single shot surveys every 75m.

ix)

17 1/2” bits will have centre nozzles.

x)

Only run sufficient number of DC’s in assemblies for the planned/ desired WOB, do not run unnecessary numbers of DC’s.

xi)

On deep 17 1/2” sections it may be necessary to shorten BHA’s to minimise the pressure drop in order to maintain high circulation rates.

xii)

All surveying to be carried out as per the BP Standard Surveying Instructions.

xiii)

Penetration rate should be limited to aid good hole cleaning. Refer to the 17 1/2” hole cleaning curves on page 6. Good hole cleaning can be maintained by keeping YP at 30+ but not less than 25.

BP EXPLORATION


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:

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:

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xiv)

WOB and RPM will be determined by directional requirements and the ROP limit.

xv)

If any major problems arise with the mud system or solids control equipment, stop drilling and circulate until rectified.

xvi)

Keep strictly to hydraulics programme, especially maximum pump rate. Never drill ahead with one pump; pull to the shoe and repair.

xvii)

Local variations in hole condition will be advised in the Well Drilling Programme. In general, wiper trips will be made every 3 stands, across problem areas. Backreaming should be considered.

xviii)

If hole packs off, attempt to work pipe down in order to regain circulation, prior to attempting to jar out.

xix)

Ensure that the hydraulic configuration between bit and MWD restrictor sub is set up correctly.

2.13

Circulate the hole clean at section TD. Condition mud as required.

2.14

Make a wiper trip to shoe. Circulate hole clean prior to running logs or casing.

2.15

Log as per Drilling Programme. Perform wiper trip as necessary.

2.16

Recover wear bushing.

2.17

On surface BOP stacks change top rams to 13 3/8” and pressure test the bonnet seals. Rig up to run 13 3/8” casing.

3.


Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26

Selection 2 3 2 2 2 12 (min.) 15 (min.) 2 2 30 3 3 1 set 1 set 1 1 set 2 sets 1 1 2 2 1 2 1

17 1/2” bits c/w jets (selection) + breaker. 17 1/2” near bit stabilisers. 17 1/2” string stabilisers/gauge tool. Sub 7 5/8” reg box-box (bored to take NRV). Float sub c/w NRV (7 5/8” reg conns). Totco ring (crows foot type). 9 1/2” steel drill collars (7 5/8” reg conns). 8” steel drill collars (6 5/8” reg conns). X/over 7 5/8” reg pin - 6 5/8” reg box. X/over 6 5/8” reg pin - 4 1/2” IF box. 5” HWDP (4 1/2” IF conns). 9 1/2” DC lift nipples. 8” DC lift nipples. 9 1/2” DC slips/elevators. 8” DC slips/elevators. DC safety clamp. Totco equipment and overshot. DP elevators/slips. Gray inside BOP (4 1/2” IF conns). Circ. head 4 1/2” IF pin - 2” Lo torque valve. Hydril kelly cock (4 1/2” IF conn). 5” DP pup joints (1 x 1.5m and 1 x 3m). Dope for DP and DC. Junk sub (7 5/8” reg conns). Drilling jars. Circulating sub (7 5/8” reg conns).

BP EXPLORATION

DRILLING MANUAL SUBJECT: 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41

Section

:

1310/GEN

Rev.

:

3 (12/91)

Page

:

5 of 6

DRILLING DEVIATED 17 1/2" HOLE 1 2 1 1 2 3 2 Selection 2 3 2 2 Set 2

Casing equipment. 9 1/2” PONY DC. Mud savers (if OBM used). Dart sub c/w dart. MWD tool if required. 17” NM stabilisers. 17 1/2” NM stabilisers. 11 1/4” mud motors if required. Bent subs as required. 9 1/2” PONY NM drill collars (7 5/8” reg conns). 9 1/2” NM drill collars (7 5/8” reg conns). Bent steerable motors if required. Double tilted U-joint housing motors (DTU) if required. Fishing tools (refer to Section 6200/GEN). 17 1/2” string roller reamers (to be considered as an alternative to the stabilisers).

Note: All equipment to be dimensionally checked and recorded before running in hole. Requisite fishing equipment should be on site.

BP EXPLORATION


Section

:

1310/GEN

Rev.

:

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:

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DEVIATED 17 1/2" HOLE CLEANING CHART

Q(gpm) * ESG TRANSPORT INDEX = ——————— 100 TRANSPORT INDEX

40

2.3

EFFECTIVE SG (ESG) 1.4 1.2 1.3

17 30 16 15

20

14

CUTTINGS SG

MAXIMUM ROP (m/h)

1.5

2.2

1.6

13

10

1.7

12 11 10 9

0 30

40 50 HOLE ANGLE (DEGREES)

60

2.1 1.2

1.3 1.4 MUD SG

1.5

PROCEDURE 1. ENTER MUD SG AND CUTTINGS SG ON RH GRAPH. READ OFF ESG FROM FAMILY OF DIAGONAL LINES. 2. USE BOXED EQUATION TO DETERMINE TRANSPORT INDEX FOR SET FLOW RATE. 3. READ OFF MAX ROP FOR HOLE ANGLE

2179 /163

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DRILLING DEVIATED 17 1/2" HOLE USING SPACER TEMPLATE

1.

The following assumes that the previous casing string is the 30” conductor and that no 20” casing has been run.

2.


2.1


2.2


2.3


2.4


2.5

Once the diverter is installed ensure that a D3 diverter drill is performed. Record the details on the IADC and Daily Drilling Reports.

2.6


2.7


2.8


3.

DRILLING GENERAL

3.1

Make up the following 30” cleanout assembly: 17 1/2” bit - 26” hole opener - bit sub - 9 x 8” DC - jar - 2 x 8” DC - X/O - 9 x 5” HWDP - DS.

3.2

RIH and drill out 30” shoe and 36” rathole using seawater.

3.3

Displace the well to a bentonite mud system.

3.4

POOH and make up the following kick-off BHA: 17 1/2” bit (3 x 24’s, 1 x 16) - 9 5/8” multilobe Magnodrill motor - bent sub - X/O - 8” SNMDC - X/O MWD - UBHO - 2 x 8” NMDC - 6 x 8” DC - jars - 2 x DC - X/O - 9 x 5” HWDP - DS.

3.5

Directionally drill 17 1/2” hole to section TD. Minimise 13 3/8” casing sump.

3.6

Displace well to a mud with minimum density of 1.15 SG. Section Notes i)

The 17 1/2” section will be surveyed whilst drilling using surface readout gyro shots until clear of magnetic influence. Once clear of interference and the inclination is above 5°, the MWD may be used. Three consecutive MWD readings must correlate with the gyro surveys before the MWD readings will be accepted on their own.

ii)

All surveying to be carried out as per the BP Standard Surveying Instructions.

iii)

The mud density is to be maintained as low as possible (max. 1.11 SG).

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iv)

Bit balling is to be expected. Attempt to remove the problem by treating the mud with 2% detergent.

v)

A contingency stock of 40 x 25 kg sacks of Guar Gum is to be held on board.

vi)

If the mud motor and bent sub need to be pulled for any reason, e.g. bit failure, the following rotary build assembly should be used to continue the build-up:17 1/2” bit - NB stab - 8” SNMDC - X/O - MWD - 17 1/2” NMSS - 8” NMDC - 17 1/2” NMSS - 8” NMDC - 9 x 8” DC - jars - 2 x 8” DC - X/O - 9 x 5” HWDP - DS.

Note: The expected right-hand walk with this assembly is 0.6 - 0.8 deg/30m.

4.

vii)

If rotary build assembly is run, ream the motor drilled build-up section on the way into bottom.

viii)

Pump hole cleaning pills as necessary prior to making connections if hole condition dictates. At high angles combined lo-vis and high weighted pills may be considered.

ix)

Circulate at max. rate to maintain annular velocity for optimum hole cleaning. Account must be taken of the effect of ECD on weak formations.

x)

17 1/2” bits will have centre nozzles.

xi)

Penetration rate should be limited to aid good hole cleaning. Refer to the 17 1/2” hole cleaning curves on page 4. Good hole cleaning can be maintained by keeping YP at 30+ but not less than 25.

xii)

WOB and RPM will be determined by directional requirements and the ROP limit.

xiii)

If any major problems arise with the mud system or solids control equipment, stop drilling and circulate until rectified.

xiv)

Keep strictly to hydraulics programme, especially maximum pump rate. Never drill ahead with one pump; pull to the shoe and repair.

xv)

If hole packs off, attempt to work pipe down in order to regain circulation, prior to attempting to jar out.

xvi)

Ensure that the hydraulic configuration between bit and MWD restrictor sub is set up correctly.

EQUIPMENT CHECK LIST Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13

Selection 2 3 2 2 2 2 15 (min.) 2 30 2 2 3

17 1/2” bits c/w jets (selection) + breaker. 17 1/2” near bit stabilisers. 17 1/2” string stabilisers/gauge tool. 26” hole opener. Sub 6 5/8” reg box-box (bored to take NRV). Float sub c/w NRV (6 5/8” reg conns). Totco ring (crows foot type). 8” steel drill collars (6 5/8” reg conns). X/over 6 5/8” reg pin - 4 1/2” IF box. 5” HWDP (4 1/2” IF conns). X/over (7 5/8” reg pin/6 5/8” reg box). X/over (6 5/8” reg pin/pin). 8” DC lift nipples.

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DRILLING DEVIATED 17 1/2" HOLE USING SPACER TEMPLATE 1 set 1 2 sets 1 1 2 2 1 2 1 2 1 2 3 2 Selection 2 3 2 Set

8” DC slips/elevators. DC safety clamp. DP elevators/slips. Gray inside BOP (4 1/2” IF conns). Circ. head 4 1/2” IF pin - 2” Lo torque valve. Hydril kelly cock (4 1/2” IF conn). 5” DP pup joints (1 x 1.5m and 1 x 3m). Dope for DP and DC. Junk sub (7 5/8” reg conns). Drilling jars. Circulating sub (6 5/8” reg conns). Casing equipment. Mud savers (if OBM used). Dart sub c/w dart. MWD tool (6 5/8” reg box/box). 17 1/2” NM stabilisers. 9 5/8” Magnadrill motors. Bent subs as required. 8” PONY NM drill collars (6 5/8” reg conns). 8” NM drill collars (6 5/8” reg conns). UBHO sub (6 5/8” reg conns). Fishing tools (refer to Section 6200/GEN).

Note: All equipment to be dimensionally checked and recorded before running in hole. Requisite fishing equipment should be on site.

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DEVIATED 171/2" HOLE CLEANING CHART

Q(gpm) * ESG TRANSPORT INDEX = ——————— 100 TRANSPORT INDEX

40

2.3


17 30 16 15

20

14

CUTTINGS SG

MAXIMUM ROP (m/h)

1.5

2.2

1.6

13

10

1.7

12 11 10 9

0 30


60

2.1 1.2

1.3 1.4 MUD SG

1.5


2179 /162

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DRILLING 12 1/4" HOLE

1.


1.1

Ensure that all drilling tools and equipment, as per the Equipment Check List on page 5, are on board, checked out and in a serviceable condition prior to Casing Drillout. Ensure that the gyro survey equipment is available (if required), after cementing the casing but before drilling out the shoe.

1.2


1.3


1.4

Ensure all BOP equipment and drillstring well control equipment is in a serviceable condition.

1.5

On fixed installations, complete wellhead pressure testing. On semi-submersible units, if the casing has been run with the full bore running tool, set and pressure test the pack-off in the wellhead (refer to Section 2300/SEM). Perform a BOP test as per Section 0420/FIX or 0420/SEM. Set wellhead wear bushing. On semi-submersible units install the flex joint wear bushing.

1.6


1.7

On floating units ensure that the emergency hang-off tool is made up in the derrick.

1.8

On floating units, prior to casing drillout, make up the 9 5/8” casing hanger to the running tool complete with pack-off and SSR plug mechanism. Stand back in the derrick or lay down on the pipe rack (refer to Section 2400/SEM).

1.9


1.10


2.

DRILLING - GENERAL

2.1

Make up the 12 1/4” drilling assembly. Vertical Wells Typical drilling assemblies for the section are: a)

Straight Well Drop-Off Assembly 12 1/4” bit - Totco - 2 x 8” DC - 12 1/4” SS - 1 x 8” DC - 12 1/4” SS - 11 x 8” DC - Jars - 3 x 8” DC 9 HWDP - DS.

Note: Location of DS depends on ID of HWDP and OD of dart. b)

Straight Well Stiff Assembly 12 1/4” bit - Totco - 12 1/4” NBS - 1 x 8” DC - 12 1/4” SS - 2 x 8” DC - 12 1/4” SS - 11 x 8” DC Jars - 3 x 8” DC - 9 HWDP - DS.

The normal practice is to run a stiff assembly unless there is angle in the hole or formations expected to be soft. For details on turbine drilling, refer to Section 1700/GEN.

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Directional Wells a)

Drill Collar Spacing to Minimise Wall Contact Using the graph of BHA Deflection and Wall Contact vs. Hole Angle (Figure 1, page 10), a stabiliser spacing of 80 ft if necessary to provide zero wall contact in wells up to 30 degrees. For well inclinations up to 60 degrees, 70 ft is the maximum spacing and over 60 degrees it is 60 ft.

b)

Quantity of Heavyweight in the Assembly A report entitled "A Review of Jar Placement Using Jarpro" Doc ID: AM/sb 6 recommends that if the prime consideration is to jar, while at the same time reducing the likelihood of differential sticking, use a BHA with a hammer composed of 2 off 8" DC's. For the WOB to be maintained, 5" HWDP can be added and is not too detrimental to jarring. Therefore with respect to jarring and differential sticking, the optimum quantity of 5" HWDP is 5 stands. Thus a typical directional tangent hold BHA in a 35 degree deviated hole would be: Bit - NBS - NMSDC - UGNMSS - MWD - 12 1/4" NMSS - 2 x 8" NMDC - 12 1/4" SS - 2 x 8" DC 12 1/4" BR - Jar - 2 x 8" DC - 15 x 5" HWDP - HDIS.

Locked Up Rotary Assemblies At commencement of this section the well should be lined up on target, hence the majority of drilling will be with “locked up” tangent assemblies. Typical “locked up” rotary assemblies are: a)

12 1/4” bit - NB stab - SNMDC - NM stab - MWD - NM stab - 8” NMDC - NM stab - 1 x 8” NMDC stab - 2 x 8” DC - jar - 5 x 8” DC - 12 HWDP - dart sub.

b)

12 1/4” bit - NB stab - 8” SDC - 11 3/4” to 12 1/4” Andergauge stab (wt. set 30K to 32K) - 8” NMDC - 12 1/4” NMSS - X/O - 8 1/4” MWD - 12 1/4” NMSS - 2 x 8” NMDC - 6 x 8” DC - Jars - 2 x 8” DC X/O - 1 x 5” HWDP - dart sub - 14 x 5” HWDP.

In assembly b) the Andergauge stabiliser is run to provide angle control. In certain situations it is possible to use a steerable turbine, or a stabilised mud motor. The advantages of the steerable turbine and stabilised mud motor are that small corrections in inclination and azimuth can be made. These motors would be used in conjunction with stratapax bits if it is determined to be economic with reduced cost/m. Turbine Assembly 12 1/4” bit - 9 1/2” turbine - NM stab - 8” NMDC - MWD - NM stab - 2 x 8” NMDC - jar - 2 x 8” DC - 12 HWDP - dart sub. For details on turbine drilling, refer to Section 1700/GEN. Mud Motor Assembly 12 1/4” bit - stabilised mud motor - SNMDC - 12” NM stab - SNMDC - MWD - 12” NM stab - 2 x 8” NMDC - 1 x 8” DC - jar - 2 x 8” DC - 12 HWDP - DS. For details of mud motors, refer to Sections 1630/GEN and 1640/GEN.

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Rebel Tool Assembly In certain situations it is necessary to correct the azimuth in this section after the GCT survey has been made. A typical assembly is as follows: Bit - 8 7/8” rebel tool - 8” SNMDC - MWD - 8” NMDC - 12 1/4” NM stab - 2 x 8” NMDC - 12 1/4” stab - 5 x 8” DC - jar - 3 x 8” DC - 12 HWDP - dart sub.

Notes: a)

The most common spacing for the stabiliser is ± 30m from the bit, a drop of 0.4 deg/30m would be typical with walk rates of 4 deg/30m.

b)

The position of the first stabiliser above the bit generally controls the characteristics of the assembly.

c)

Field history with rebel tool runs should be used to determine exact assemblies in each case.

d)

For details of rebel tools, refer to Section 1660/GEN.

e)

Jars are to be run in the string, keeping the neutral point away from the jars whilst drilling. It is advisable to use the Jarpro programme to optimise jar placement.

f)

The minimum BHA length should be run, equal to the maximum WOB that is required.

g)

HWDP will always be run. i) ii)

2.2

Minimum number of joints will be run to give adequate stress reduction. If possibility of differential sticking or losses exists, the amount of HWDP is to be increased and the number of DC’s decreased.

h)

On directional wells the rebel tool should be kept on site for any azimuth corrections c/w LH and RH paddles.

i)

A junk sub should be considered in the BHA prior to using a PDC or diamond bit (corehead), corebarrel or turbine.

j)

The OD, ID and length of each string component is to be recorded before it is RIH. Ensure that the ID of all downhole tools, such as bumper subs, jars and shock subs, etc., is large enough to allow FPI, back-off and survey recovery tools to pass.

k)

Ensure that the correct overshot grapples are on board to catch all tool OD’s run in the hole.

l)

The length of the fishing necks of each string component are to be recorded.

RIH. (Drill out stage cementer if installed and pressure test casing to 13 3/8” cement plug bump pressure.)

Note: a) Be aware of the danger of the bit drilling through the centre of the plug, leaving the outer section to ride up above the bit. This may cause a hydraulic piston effect that can result in pumping the drillstring out of the hole. 2.3

RIH and tag TOC (report TOC). Pressure test the casing if required. Perform D5 kick drill and record the details on the IADC and Daily Drilling Reports.

2.4

Drill out 13 3/8” shoe track, closely monitoring torques. Note and report hardness of cement in shoe track. If required, after drilling half the shoe track, displace well to new mud.

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Notes:

2.5

a)

Ensure that the mud is pre-treated against cement contamination.

b)

It is not recommended to drill the shoe track or stage cementer with a bit softer than that of the 1.3.4 IADC category.

c)

Confirm float equipment in PDC drillable prior to using PDC bit to drill out. Care must be taken when “bedding” in the bit (see Section 1500/GEN).

d)


Clean out the pocket and drill 3m of new hole. Circulate to clean the hole and balance the mud. Pull back to the shoe and perform a leak-off test. (Refer to Section 7100/GEN.) This test may be limited on advice from the drilling office, depending on the mud weight and kick margin requirement for the 12 1/4” section. Fax the leak-off test graph to town and record the results in the well file and Daily Drilling Report. Re-calculate the kick tolerance and inform the Drilling Superintendent if less than 100 bbls. The kick tolerance should then be re-calculated every day (refer to Section 0405/GEN). Take SCR’s.

Notes:

2.6

a)

The leak-off test surface pressure is limited to the casing test or cup type test pressure, whichever is the least.

b)

On exploration wells a gyro survey may be required in the 13 3/8” casing - refer to the survey programme.

On exploration wells drill/core ahead to TD with magnetic single shot surveys and wiper trips as required. Pit drills are to be carried out every tour. On development wells drill ahead 230 - 300m into the section. This is the minimum length permissible for a GCT survey. The hole curvature should not change at more than 0.5 deg/30m. If the target size is big enough the bit can be dulled before making the survey. Run Schlumberger GCT or equivalent. Ensure hole is clean and mud is in good condition prior to running the GCT. After completing the GCT survey drill/core ahead to the section TD (refer to Section 7000/DEV). Section Notes i)

On exploration wells BOP tests are to be carried out every 10 - 14 days maximum. On development wells a full BOP test is to be carried out prior to drilling through a reservoir (if present in this section). At the same time the MWD tool will be left out of the BHA unless otherwise instructed.

ii)

Full scale kick drills are to be carried out on trips and reported.

iii)

On exploration wells a tandem electronic multishot survey will be required, either prior to entering the reservoir, or at 12 1/4” TD. (Refer to the survey programme.) Ensure that the nonmagnetic drill collars, etc. are in the BHA prior to reaching the survey point.

iv)

If the MWD fails on development wells, continue to drill ahead with single shot surveys every 90m, unless instructed otherwise.

v)

All surveying to be carried out as per the Standard Surveying Instructions.

vi)

If any major problems arise with the mud or solids control equipment, stop drilling and circulate until rectified.

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vii)

When drilling with high ROP’s, always circulate to ensure hole is clean prior to tripping.

viii)

Normal circulation rates for this section are 650 - 750 gpm. For optimum circulation rates refer to the 12 1/4” hole cleaning curves on pages 8 and 9.

At section TD circulate to clean the hole and condition the mud. On development wells prior to POH for logging, drop a tandem solid state EMS.

2.8

POH confirming hole depth measurements.

2.9

Log as programmed. A check trip may be required depending on hole conditions and the length of the logging programme. On exploration wells, this will afford the possibility of re-running the magnetic multishot if required.

2.10

If hole conditions dictate, check trip prior to running the casing. Condition the hole and mud to reduce surge pressures.

Note: On exploration wells if the 12 1/4” section TD is the well TD, 9 5/8” casing will only be run in the event of a well test. If the well is to be plugged and abandoned after logging, RIH with the cementing stinger, circulate to condition the mud and set cement plugs as programmed (refer to Section 3600/GEN). 2.11

If 9 5/8” casing is to be run retrieve the wear bushing(s). On surface stacks change the top pipe rams to 9 5/8” casing rams unless advised otherwise in the Drilling Programme. Pressure test the bonnet seals against the annular preventer using the test plug assembly - ensure that the string is open when testing.

Note: If 13 3/8” casing has been omitted then a 21 1/4” BOP might be installed when running 9 5/8” casing. Top rams are likely to be blind/shear and therefore cannot be changed to 9 5/8” casing rams. 2.12

Rig up to run 9 5/8” casing.

3.


Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Selection 2 4 2 1 2 30 2 30 3 1 set 1 2 1 set 2 sets 1 1 2 -

12 1/4” bits c/w jets (selection) + breakers. 12 1/4” near bit stabilisers. 12 1/4” string stabilisers/gauge tool. Andergauge stabiliser (11 3/4” to 12 1/4”). 12 1/4” roller reamer plus spare cutters. Sub 6 5/8” reg box-box bored to take NRV. 8” steel drill collars (6 5/8” reg conns). X/over 6 5/8” reg pin - 4 1/2” IF box. 5” HWDP. 8” DC lift nipples. 8” DC slips/elevators. DC safety clamp. Totco ring (ring type). MSS equipment. DP elevators/slips. Gray inside BOP (4 1/2” IF conns). Circ. head 4 1/2” IF pin - 2” Lo torque valve. Hydril kelly cock (4 1/2” IF conns). 5” DP pup joints. Dope for DP and DC.

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DRILLING 12 1/4" HOLE 2 2 1 1 3 As required Selection if applicable If applicable 2 if required 2 if required 2 if required If applicable Selection 1 Set 2

Junk sub with 6 5/8” reg conns. Drilling jars. Circulating sub (6 5/8” reg conns). Dart sub (4 1/2” IF conns). Casing equipment. Gyro survey equipment (if required). Magnetic multishot equipment. 8” non-magnetic drill collars (6 5/8” reg conns). 12 1/4” non-magnetic string stabilisers (6 5/8” reg conns). 8” Pony non-magnetic drill collars (6 5/8” reg conns). MWD tools. 9 1/2” turbines. Stabilised mud motors. 8 7/8” rebel tools c/w LH and RH paddles. Corebarrel assembly. Coreheads. 13 3/8” RTTS plus storm valve (or equivalent) and safety joint. Fishing tools (refer to Section 6200/GEN). 13 3/8” bridge plug (exploration/appraisal wells) and setting tool.

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40


PROJECTION LINE

PROJECTION LINE

50

PROCEDURE

CUTTINGS SIZE (in) 1/4



30

300


17 1/2

1/2 20

200

100

12 3/4 8 1/2

80

HOLE DIAMETER (in)


60

10

100 40 20

0

0

0 PLASTIC VISCOSITY (cP)

YIELD POINT (lb/100ft 2 )

PROJECTION LINE

PROJECTION LINE



60 50 40

2.1

2.2 MUD SG

1.0 2.3

30 60

300

2.0

20

2.4

50

1.5

200

40 1.0 MUD SG

2.5 10 1/4" CUTTINGS


30


1.5

100 2.6 20


1/2" CUTTINGS 0 EFFECTIVE VISCOSITY (cP)

2.0

2.7

CUTTINGS SG


2179 /159

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12 1/4" VERTICAL HOLE CLEANING

CUTTINGS SLIP VELOCITY (ft/min) 60 50

40 30 20

PENETRATION RATE (m/h)

10

60 50

0

40

30

20

PIVOT POINT

10

180 140 100 80

60

50

40

30

20



2179 /160

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Q(gpm) * ESG TRANSPORT INDEX = ——————— 100 TRANSPORT INDEX 11

50

2.5

EFFECTIVE SG (ESG) 1.2 1.3 1.4 1.5

1.6

30

10

20

9

CUTTINGS SG

MAXIMUM ROP (m/h)

40

2.4 1.7

8

10

7 0 40

50 60 70 HOLE ANGLE (DEGREES)

80

2.3 1.2

1.3

1.4 1.5 MUD SG

1.6


2179 /161

SUBJECT:

FIGURE 1

PLOT OF BHA DEFLECTION AND WALL CONTACT 12 1/4" HOLE - 8" x 2 3/4" DC WELL BORE

90

80

60

50

40

30

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1350/GEN

20

Page

HOLE ANGLE (DEGREES)

70

BP EXPLORATION

90FT

80FT

DRILLING MANUAL

70FT


60FT

10

0 0

1

BHA DEFLECTION (INS)

2

5

10

15

20

25

WALL CONTACT (FT)

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1.


1.1

Ensure that all drilling tools and equipment, as per the Equipment Check List on page 4, are on board, checked out and in a serviceable condition prior to Casing Drillout. Ensure that the gyro survey equipment, if required, is available after cementing the casing but before drilling out the shoe.

1.2


1.3

Ensure that logging tools/operators, survey tools/operators (if required) and casing running tools/operators are all on board prior to reaching the 8 1/2” section TD.

1.4


1.5

Complete wellhead pressure testing, and carry out a BOP test as per Sections 0420/FIX and 0420/SEM. Set wellhead wear bushing. On semi-submersible units install the flex joint wear bushing.

1.6

Check the ID of all downhole equipment for passage of a FPI tool and survey instrument fishing tools confirm passage of drop-in dart through jars.

1.7

On floating units ensure that the emergency hang-off tool is made up in the derrick.

1.8


1.9


1.10

Ensure that a 8 1/2” string reamer is on board for the duration of the 8 1/2” hole drilling and 7” casing operations.

2.

DRILLING - GENERAL

2.1

Make up the 8 1/2” drilling assembly. Vertical Wells Where differential sticking is known not to be a problem. Typical drilling assemblies for this section are: Straight well drop-off assembly: 8 1/2” bit - bit sub - Totco - 2 x 6 1/4” DC - 8 1/2” SS - 1 x 6 1/4” DC - 8 1/2” SS - 11 x 6 1/4” DC - DS 6 1/4” jars - 2 x 6 1/4” DC - 3 HWDP. Straight well locked-up assembly: 8 1/2” bit - 8 1/2” NBS - Totco - 1 x 6 1/4” DC - 8 1/2” SS - 2 x 6 1/4” DC - 8 1/2” SS - 11 x 6 1/4” DC DS - 6 1/4” jars - 2 x 6 1/4” DC - 3 HWDP.

Notes: -

If it is planned to run a turbine assembly, a stiff assembly should always precede the turbine BHA. For details on turbine drilling see Section 1700/GEN.

-

If formation dips have been identified as a problem, then a stiffer assembly should be run.

-

Drill collars below jar, number dependent on desired weight on bit.

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Directional Wells On completion of the previous section, the hole will usually have been lined up on the target, and drilling will be carried out with a “locked-up” assembly. Since the 8 1/2” section is normally drilled through the pay, the assembly should be designed to minimise the possibility of differential sticking. This is done by: a)

Minimising Wall Contact of the Drill Collars: A report entitled “BHA Deflection in Deviated Holes” (12/12/90) concluded that, in 8 1/2” hole, a stabiliser spacing of 60 ft is necessary to provide zero wall contact in wells of up to c. 35 degrees inclination. For inclinations greater than 35 degrees, a stabiliser every 30 ft is necessary. Jars are to be considered the same as drill collars. A series of curves showing wall contact for various hole angles and stabiliser spacings can be found at the end of this section. These are to be referenced when high inclinations are anticipated; and, since sticking of the Hevi-Wate can occur,

b)

Minimising the Quantity of Hevi-Wate in the Assembly: A report entitled “Drilling Jar Optimisation in 8 1/2” BHA’s” (19/12/90) concluded that, from a jarring viewpoint, the optimum assembly above the jars consists of 2 collars and 3 Hevi-Wate drill pipe.

Note: Additional HWDP reduced jarring effectiveness. Thus, typical assemblies would be: 1)

Bit - NBS - SDC - SS - DC - SS - 2 DC - SS - 2 DC - SS - 2 DC - SS - Jar - DC - 7 3/4” SS - DC - 3 HWDP or, where directional information is required:

2)

Bit - NBS - SNMDC - NMSS - MWD - NMSS - (TR) - 2 NMDC - SS - 2 DC - SS - 2 DC - SS - Jar DC - 7 3/4” SS - DC - 3 HWDP.

Note: a)

Any additional WOB required should be as DC plus stabilisers below the jar.

b)

A Totco ring should be run in addition to the MWD for single shot/ multi shot surveys.

c)

Jars will always be run. Keep the neutral point away from the jars while drilling (guideline - 80% for available weight on bit - neutral point from jar).

d)

Hevi-Wate DP will always be run.

e)

The minimum BHA lengths should be run to provide the maximum WOB required.

f)

A junk sub should be considered in the BHA prior to using a PDC or Diamond bit (corehead), core barrel or turbine.

g)

Consideration should always be given to using roller reamers in place of stabilisers, particularly directly above the bit, and definitely after coring. The modern sealed bearing roller reamer offers no disadvantages over stabilisers for this purpose, and can considerably reduce required rotating torque.

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h)

Stabilisers higher than the first three above the bit do not need to be full gauge, as they fulfil no directional purpose.

i)

The OD, ID and length of each string component is to be recorded before it is run in hole. Ensure that the ID of all downhole tools, such as bumper subs, jars and shock subs, etc. is large enough to allow FPI, back-off and survey recovery tools to pass. A slimhole wireline overshot may be required to recover survey instruments.

RIH and drill out Stage Cementer if installed. Pressure test casing to 9 5/8” cement plug bump pressure.

Note: a)

If a gyro survey is required in the 9 5/8” casing, this will be run as instructed by the Drilling Office.

b)


2.3

RIH and tag TOC (report TOC). Pressure test the casing, if required. Perform D4 and D5 kick drill and report the results on the IADC report.

2.4

Drill out the 9 5/8” shoe track, closely monitoring torque. Note and report hardness of cement in shoe track.

Note:

2.5

a)

Ensure that the mud is pre-treated against cement contamination.

b)

It is not recommended to drill the shoe track or stage cementer with a bit softer than that of the 1.3.4 IADC category.

c)

If drilling out with a PDC bit, refer to Section 1500/GEN.

d)

If mud conditioning or mud changeout is programmed, peform this while drilling out the shoe track.

e)


Clean out the pocket and drill 3m of new hole. Circulate to clean the hole and balance the mud. Pull back to the shoe and perform a leak-off test (refer to Section 7100/GEN). This test may be limited on advice from the drilling office, depending on mud weight and kick margin requirements in the 8 1/2” section. Fax the leak-off test graph to town. Re-calculate the kick tolerance and inform the Drilling Superintendent if less than 100 bbls (refer to Section 0405/GEN). Take SCR’s.

Note: The leak-off test surface pressure is limited to the casing test or cup type test pressure, whichever is the least. 2.6

On exploration/appraisal wells drill/core to section TD taking surveys as required (refer to Section 7000/EXP). On development wells drill/core ahead to section TD taking single shot inclination surveys as required (refer to Section 7000/DEV - Standard Survey Instructions).

Note: a)

Take SCR’s every 500m drilled or when the mud weight is changed.

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b)

The Drilling Programme will advise section TD, MWD requirements if any, any coring requirements, reservoir pressure data, mud weight data and potential drilling hazards.

c)

BOP tests are to be carried out every 10 - 14 days maximum. Pit drills are to be carried out every tour.

d)

Kick drills are to be carried out on trips and reported.

e)

On exploration/appraisal wells a tandem electronic multishot survey may be required at TD. If so, ensure that non-magnetic drill collars are in the BHA prior to reaching TD.

f)

Normal circulation rates for this section are 400 - 450 gpm. For optimum circulation rates refer to the 8 1/2” hole cleaning curves on pages 7 and 8.

2.7

At section TD circulate to clean the hole and condition the mud. Survey the hole as directed by the drilling programme.

2.8

POOH confirming hole depth measurements.

2.9

Log as programmed. A check trip may be required depending on hole condition and length of logging programme.

2.10

Check trip prior to running the casing if required. Condition the hole and mud. POOH confirming hole depth measurements and laying out the dart sub if a liner is to be run. On development wells install NMDC’s on the check trip and drop a tandem solid state EMS before POOH for casing.

2.11

Rig up to run the 7” liner.

Note:

3.

a)

On exploration/appraisal wells, a 7” liner will normally be run if it is decided to test the well. If the well is to be plugged and abandoned after logging, RIH with the cementing stinger, circulate to condition the mud and set cement plugs as programmed (refer to Section 3600/GEN).

b)

If a rotating 7” liner is programmed, ensure rotary torque readings are taken on bottom and inside 9 5/8” casing at 10, 15 and 20 RPM for use during liner cementing.

c)

In sidetracking or special directional situations, variations to the above will be advised in the Drilling Programme.


Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14

Selection 1 2 4 2 if required 2 30 5 1 2 1 set 1 set 2 sets 1

8 1/2” bits c/w jets (selection) + breakers. 8 1/2” junk mill. 8 1/2” near bit stabilisers. 8 1/2” string stabilisers/gauge tool. 8 1/2” roller reamer + NB roller reamer. Bit sub (4 1/2” Reg box/4” IF box). 6 1/4” drill collars. 5” HWDP. DC safety clamp. Totco ring (ring type). Totco equipment and overshot (slim hole o/shot/heat shield may be needed). DC slips/elevators. DP elevators/slips. Gray inside BOP.

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15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

1 1 1 2 1 1

32 33 34 35 36

1 1 Set As required 1

3 if required 1 if required 1 lot As required If required If required Selection

Circ. head 2” torque valve. Hydril kelly cock. 5” DP pup joints. Dope for DP and DC. Junk sub (connections to match drill collars). 6 1/4” OD drilling jars. Circulating sub. Dart sub. Liner equipment (Section 2500). 6 1/4” non-magnetic drill collars. 8 1/2” non-magnetic string stabiliser. Undergauge stabilisers (if required). 6 1/4” Pony drill collars (steel and non-mag). Gyro survey equipment. Magnetic multishot equipment. Core barrel assembly (typically 6 3/4” OD x 4 3/8”). 8 1/2” coreheads. (Note: a slimhole o/shot required for the core barrel assembly in 8 1/2” hole.) 9 5/8” bridge plug with DP running tool. 9 5/8” RTTS and storm valve (or equivalent). Fishing tools (refer to Section 6200/GEN). TD logging suite. 7 3/4” string stab.

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40


PROJECTION LINE

PROJECTION LINE

50

PROCEDURE

CUTTINGS SIZE (in) 1/4



30

300


17 1/2

1/2 20

200

12 1/4

100

8 1/2

80

HOLE DIAMETER (in)


60

10

100 40 20

0

0

0

YIELD POINT (lb/100ft 2 )


PROJECTION LINE

PROJECTION LINE



60 50 40

2.1

2.2 MUD SG

1.0 2.3

30 60

300

2.0

20

2.4

50

1.5

200

40 1.0 MUD SG

2.5 10 1/4" CUTTINGS


30


1.5

100 2.6 20


1/2" CUTTINGS 0 EFFECTIVE VISCOSITY (cP)

2.0

2.7

CUTTINGS SG


2179 /156

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8 1/2" VERTICAL HOLE CLEANING CUTTINGS SLIP VELOCITY (ft/min) 40

50

60

30 20 10 0

PENETRATION RATE (m/h) 40

30

20

PIVOT POINT

10

180 140 100 80

60

50

40

30

20



2179 /157

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40

TRANSPORT INDEX

30

6

20 5

2.7

CUTTINGS SG

MAXIMUM ROP (m/h)

Q(gpm) * ESG TRANSPORT INDEX = ——————— 100


2.2 2.6

10 4 3

0 30

40


80

90

2.5 1.2

1.4 1.6 1.8 MUD SG

2.0

PROCEDURE 1.ENTER MUD SG AND CUTTINGS SG ON RH GRAPH. READ OFF ESG FROM FAMILY OF DIAGONAL LINES. 2.USE BOXED EQUATION TO DETERMINE TRANSPORT INDEX FOR SET FLOW RATE. 3. READ OFF MAX ROP FOR HOLE ANGLE

2179 /158

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DRILLING MANUAL

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IAJ / 03 / KR-1 910032 / 2

FIGURE 1

Page

40 30 20 10 1 0.75 0.50 0.25 0

90 FT 80 FT 70 FT 60 FT 50 FT 30 FT

WALL CONTACT ( FEET ) BHA DEFLECTION ( INS )


70

HOLE ANGLE ( DEGREES )

SUBJECT:

100

PLOT OF BHA DEFLECTION AND WALL CONTACT 8 1/2 " HOLE – 6 1/2 " x 2 3/4 " DRILL COLLARS

WELL BORE

BP EXPLORATION

DRILLING MANUAL DRILLING 8 1/2" HOLE

70

60

50

40

30 HOLE ANGLE ( DEGREES )

SUBJECT:

90

60 FT

6 1/2 " O.D. DRILL COLLAR 6" O.D. DRILL COLLAR 10

80

20

Rev.

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:

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0

IAJ / 03 / KR-06 910032 / 1

FIGURE 2

Page

WALL CONTACT ( FEET )

60 50 40 30 20 10 0

70 FT

80 FT

90 FT

EFFECT OF DECREASING COLLAR O.D. IN 8 1/2 " HOLE 6" AND 6 1/2 " DRILL COLLARS WITH 2 3/4 " I.D.

100

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DRILLING 6" HOLE

On exploration and appraisal wells drilling 6” hole is not a normal operation and a specific programme will be compiled as and when required. On development wells drilling 6” hole is commonly undertaken. If 6” hole is planned then the 7” liner must be drifted to suit, e.g. 32 lb/ft will have to be special drift unless 5 7/8” hole is drilled.

2.

PRE-DRILLOUT OPERATIONS - DEVELOPMENT WELLS

2.1

Ensure that all drilling tools and equipment, as per the Equipment Check List on page 2, are on board, checked out and in a serviceable condition prior to Casing Drillout. Ensure that the gyro survey equipment, if required, is available after cementing the casing but before drilling out the shoe.

2.2

Ensure that all fishing tools relevant to Drilling Operations on the 6” hole section are on board, checked out and in a serviceable condition prior to Casing Drillout (refer to Section 6200/GEN).

2.3

Ensure that logging tools/operators and casing running tools/operators are all on board prior to reaching the 6” section TD.

2.4


2.5

Complete wellhead pressure testing, and carry out a BOP test as per Section 0420/FIX. Set wellhead wear bushing.

2.6

Check the ID of all downhole equipment for passage of FPI tool and survey instrument fishing tools.

2.7


2.8

Ensure that all relevant BOP drills, in accordance with the guidelines listed in the BP Well Control Manual, are understood by all rig personnel and are implemented at the relevant stages of 6” Hole Drilling Operations.

2.9

Ensure that a 6” string reamer is on board for the duration of the 6” hole drilling and casing operations.

2.10

7” casing float equipment must be of a drillable nature. Therefore, equipment such as the Weatherford Type 724 SS float shoe must be used.

2.11

If drilling 6” hole with high mud overbalances, MWD drilling and RFT logging are high risk and costly options to be avoided if at all possible.

2.12

Prior to drilling out the 7” liner, positive testing and/or drawdown testing may be done at different stages of liner cleanout, depending on the objectives of the tests. Extreme care should be exercised with all wellbore pressure testing, especially with differing mud weights in hole. All pressure testing should be conducted as per Leak-Off Testing Section 7100/GEN. Individual Well Programmes will advise precise pressure testing requirements.

3.

DRILLING - GENERAL

3.1

After completion of BOP testing and installation of the wear bushing, make up the 6” drilling assembly. Normally, there are no directional requirements to fulfill on 6” hole sections and the hole will be drilled with a packed rotary assembly. PDC bits have proved to be more effective at drilling the 6” reservoir section than insert tri-cone bits. A typical 6” packed assembly would be: 6” bit - 6” NBS - 4 3/4” NMDC - 6” NMSS - Totco - 4 3/4” NMDC - 6” NMSS - 4 3/4” NMDC - 2 x 4 3/4” DC - 6” SS - 7 x 4 3/4” DC - jar - 2 x 4 3/4” DC - 3 1/2” DP* - X/O - circ. sub - HDIS - 5” DP.

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DRILLING 6" HOLE

* Run sufficient 3 1/2” DP to keep the X/O above the 7” PBR with the bit at the deepest prognosed TD. 3.2

RIH to +/- 20m above 7” float collar.

3.3

Perform positive pressure test on 9 5/8”/7” liner lap to the test pressure advised in the Drilling Programme.

Note: A JM tie-back packer assembly or equivalent will be available as a contingency in the event that a pressure test is not obtained. 3.4

Clean out liner as per Section 3450/GEN.

3.5

Pressure test the 7” liner to the pressure advised in the Drilling Programme. Perform kick drill.

3.6

Drill out the remainder of the shoe track and sump, plus 3m of new hole.

3.7

Perform a leak-off test, as per Section 7100/GEN. Calculate the limited kick tolerance (refer to Section 0405/GEN).

3.8

Work the junk subs (if run) and drill/core ahead 6” hole to TD.

Note: a)

Non-magnetic drill collars will be run as part of all 6” drilling and coring assemblies, in case TD is called and a definitive ESI survey is dropped when POH.

b)

When 6” coring assemblies are in use, do not put a Totco ring in the string. The survey barrel will land on the “drop-in” ball.

c)

Core barrels with heavy duty threads must be used to reduce the chances of connection belling on these small diameter (4 3/4” x 2 5/8”) barrels. Barrel lengths should generally be limited to 30m due to strength considerations.

3.9

Circulate and condition hole for logging.

3.10

Check trip to the 7 “ shoe.

3.11

RIH and circulate clean.

3.12

POH, taking an ESI survey.

4.


Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12

Selection 1 1 2 4 2 2 24 3 String 1 set 1

6” bits c/w jets and breakers. 5 7/8” junk mill. 4 3/4” junk sub. 6” NB stabiliser (3 1/2” IF conns). 6” string stabilisers (3 1/2” IF conns). 6” NM string stabilisers (3 1/2” IF conns). 4 3/4” OD sub 3 1/2” Reg box - 3 1/2” IF box. 4 3/4” drill collars (3 1/2” IF conns). 6” NM drill collars (3 1/2” IF conns). 3 1/2” drill pipe with 4 3/4” OD x 3 1/2” IF conns. (3 1/2” 13.3 lb/ft S135). 4 3/4” DC slips/elevators. DC safety clamp.

BP EXPLORATION

DRILLING MANUAL SUBJECT: 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28

DRILLING 6" HOLE 2 sets 2 sets 2 sets 3 1 2 1 1 1 2 20 If required Set 1

3 1/2” DP elevators/slips (SDL). Type “C” BJ tongs. Conversion heads for rig tongs for 4 3/4” OD. 3 1/2” DP pup joints. 4 3/4” DC lifting subs. Junk subs (3 1/2” Reg conns). 4 3/4” OD Hydril kelly cock (3 1/2” IF conns). Gray inside BOP (3 1/2” IF conn). 4 3/4” dart sub (3 1/2” IF conns). 4 3/4” OD circ. sub (3 1/2” IF conn). 4 3/4” OD drilling jars. 3 1/2” HWDP (3 1/2” IF conns). DP and DC dope. Core barrels and coreheads (4 3/4” x 2 5/8”). Fishing tools (refer to Section 6200/GEN). 6” near bit roller reamer.

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DRILLING CASING FLOATATION EQUIPMENT WITH PDC BITS

1.

GENERAL

1.1

It may be possible to drill out casing floatation equipment with a PDC bit using rotary or turbine drilling techniques. This eliminates the need to perform a separate casing clean-out trip. This will only be attempted if the next section of open hole is suited to PDC drilling.

1.2

On exploration/appraisal wells, when the nature of the formations are uncertain, it may be advisable to drill out the float equipment and open hole with a re-run or repaired PDC bit in the first instance.

1.3

It must be certain that there is no junk, such as rock bit teeth or CST bullets, lying below the casing shoe. The risk of casing accessories producing junk must also be taken into consideration. Beware of damaging a PDC bit where there is a high DLS in the shoe track.

1.4

It is advisable to use a PDC bit with a minimum of PDC cutters on the gauge area. Gauge cutters, if present, should be of the flat profile type rather than the circular profile type in order to avoid damage while rotating in the casing.

1.5

Casing float equipment must be threadlocked to overcome the greater right hand torque produced by the PDC cutting action.

1.6

Consideration should be given to using non-rotating float and plugs.

2.

FLOAT EQUIPMENT

2.1

There must be no ferrous metallic content in the float equipment, and the aluminium content must be kept to a minimum.

2.2

Only single stage float equipment and drillable liner accessories are to be drilled with PDC bits.

3.

DRILLING PARAMETERS

3.1

Recommended parameters for drilling float equipment with PDC bits are: WOB RPM SPM

-

5 - 20,000 lbs. 60 - 100. as for normal drilling.

Note: a) Be aware of the danger of the bit drilling through the centre of the plug, leaving the outer section to ride up above the bit. This may cause a hydraulic piston effect that can result in pumping the drillstring out of the hole. 3.2

The main indicator of progress is rotary efficiency. Off bottom torque must be recorded and the torque limit set to 2 - 3 times the corresponding amperage. The rotary torque gauge must indicate some value greater than the off bottom torque to indicate progress. Erratic torque will also be a good indication that progress is being made.

3.3

Stalling of the rotary table may occur when drilling the rubber plugs. If this occurs, release the torque slowly, pick up and work the bit free of the obstruction before recommencing drilling.

3.4

When drilling out of the casing with a PDC bit on a turbine, observe normal turbine drilling procedures and maintain the minimum WOB necessary to make progress (refer to Section 1700/GEN).

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MUD MOTORS

POSITIVE DISPLACEMENT MOTORS The PDM was developed to supply bottom hole rotation of a bit without the cost or complexity of turbodrills. The PDM operates on the Moineau principle, operating in the reverse fashion to a pump. Fluid driven motors are positive displacement if, for each volume of fluid passing through the motors, the output shaft turns a corresponding amount. The typical Moineau PDM consists of four basic components (refer to Figure 1): -

Bypass valve. Motor assembly. Universal joint assembly. Bearing assembly.

The bypass valve allows the string to fill and drain while tripping as the motor assembly will not allow drilling mud to pass through the tool under hydrostatic conditions. The motor assembly, which consists of a polished steel rotor inside an elastomeric stator which forms the outer body of the motor, converts hydraulic horsepower to mechanical horsepower. The torque and speed depends on the number of lobes, stage length and cross-sectional area of the void space between motor and stator. The polished steel rotor and elastomeric stator are formed in a helix with a round cross-section which is unique to the Moineau mechanism (see Figure 2). When the motor is assembled there is a continuous seal along its length between the rubber stator and the matching points on the spiral rotor shaft. As mud is pumped through the cavities between the rotor and stator, the hydraulic pressure causes the shaft to rotate within the stator. The universal joint assembly transmits the eccentric rotation of the motor to concentric rotation at the drive shaft which rotates the bit. The bearing assembly is made up of radial bearings, which centralise the output drive shaft and thrust bearings which, in turn, react against the downward force created by the pressure drop across the motor and the upward bit force. The PDM comes in a variety of sizes to drill hole sizes from 2” - 26”. The RPM of the rotor is directly proportional to the flowrate. Each tool can operate under a wide range of flowrates to optimise for the particular use. 1.1

Types of PDM Most PDM’s in use are of the 1-2 lobe system although multi-lobed systems are available, e.g. 9-10 lobe (see Figure 2). At present the 1-2 lobe systems are much easier to manufacture. It is much more difficult to match the rotors and stators in multi-lobed systems. The development of the multi-lobed system is very important, however, as they introduce a wider range of rpm to bring the speed down to that recommended for rock bits. Much higher available torque is also produced. The geometric arrangement acts as a gear reducer producing a slower rpm. Applications of Downhole Motors 1.

Kick off sections.

2.

Azimuth control in deviated wells - bent subs, offset stabilisers.

3.

Sidetracking past a fish, or to a new target, off a cement plug.

4.

Reduce hole angle and/or dog legs in vertical wells.

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MUD MOTORS

5.

Reduced casing wear - particularly in highly deviated production wells.

6.

Allows wells to be drilled where deviation/dogleg severity produces high torque values.

Kick Off Sections The PDM has been used extensively, particulary in the North Sea with its multiwell platforms, for the initial kick off section in a well. The PDM has been particularly efficient and cost effective in the kick off sections of a deviated well from a platform. The PDM is normally used with a bent sub and oriented in a particular direction. The size of the bent sub can be altered to provide the required build rate for the well. Table 1 (page 10) illustrates the rate of build achievable over 30m for various bent subs when using a Dynadrill PDM. As a general rule, when used with a bent sub the hole deflection achieved over 10m is about 75% of the bent sub angle. The rate of build is also achieved in a reasonably smooth fashion with no wide swings in dog leg severity. It is relatively easy to build and turn during the kick off using a PDM and a bent sub. When used with a double tilt unit (DTU) the PDM assembly can be used to drill straight, by rotating the drill string, or to deviate, by orienting the tool and drilling without rotation. The DTU housing replaces the standard U-joint housing in the conventional tool. As an example, Christensen quote the following theoretical BUR’s for their Navidrill (Mach 2)/DTU assembly: Tool Size

Hole Size

DTU Angle

BUR deg/30m

6 3/4”

8 1/2”

0.32° 0.64°

2° 4°

9 1/2”

12 1/4” 17 1/2”

0.38° 0.59°

2° 4°

11 1/4”

17 1/2” 24”

0.41° 0.78°

2° 3.8°

The well course can be monitored by using either an MWD tool or a steering tool to control the tool face setting. 1.3

Azimuth Control Rotary drilling is affected by the natural walk tendency of the well. This will vary according to the particular area or even the well direction in a particular field. Generally we find that wells tend to walk to the right. Well planning allows for a certain amount of walk while drilling, but where this proves excessive in a particular well the well course has to be turned back on its planned line. Using downhole motors, this can be achieved reasonably quickly using a PDM and bent sub and orienting the bent sub to the required azmiuth. The bent sub is pointed a certain number of degrees left of highside depending on whether hole angle has to be maintained or not. On occasions, where azimuth is such that the hole is still pointing within the target, a straight hole stabilised mud motor may be employed. Experience with Dynadrills and Navidrills in the Beatrice field

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MUD MOTORS

shows that the azimuth tends to hold with the possibility of very minor RH walk where normal RH walk is excessive with normal rotary assemblies. Typical Navidrill Assembly 12 1/4” bit - 12 1/4” short N/B stab - navidrill (intergrally stabilised) - X/O - 11 1/2” stab - 8” MDC 12 1/4” NM stab - X/O - teleco - 12 1/4” NM stab - totco - 2 x 8” MDC - 12 1/4” stab - 3 x 8 DC - jars - 6 x 8 DC. This assembly would give a holding to slight drop tendency in a 65° well. The advantages of using the stabilised navidrill as opposed to a turbine are: i) ii) iii) iv) 1.4

Less pressure drop - less pump wear. Less RPM at bit sealed bearing rock bits can be used. More torque available at bit. Cheaper operation - hence less CPF.

Sidetracking Wells may need to be sidetracked for various reasons. a) b) c)

Redrill the well to a new target. Sidetrack past a fish. Sidetrack due to hole problems.

The well is normally kicked off a cement plug by undercutting the hole and turning the bent sub to head in the new required direction. Again this is more efficient than, for example, a Whipstock, as the hole can be controlled more effectively. Where sidetracking out of a window in casing the Whipstock could feasibly rotate at some stage causing the pipe to stick. 1.5

Reduce Hole Angle Vertical holes invariably have some hole angle in them. If the angle builds too much to possibly miss the bottom hole target pendulum assemblies are run to drop off angle again. This may result in a loss of penetration rate due to reduce weights on bit while farming the bottom of the hole to try and drop angle. The PDM and bent sub can be used very effectively to reduce hole inclination. Drilling with a combination of rotary assemblies and use of PDM can be very effective. Comparison with Other Methods of Kicking Off a Well a)

Badger bits.

b) Whipstocks.

a)

The badger bit is a two cone bit with one nozzle blocked off. More generally a three cone bit was used - with one large nozzle and the other two blocked off. The hole was jetted in one direction to create a ledge. Kick off was generally slower with this method and only really effective in soft formations where jetting is possible.

b)

Whipstock The whipstock basically acts as a 4” steel wedge which can be oriented to kick the bit off in a particular direction. This method is not very efficient if the well plan has to build and turn past other wells as several trips would be required.

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MUD MOTORS

Neither of these methods can provide the flexibility or ease of operation of a PDM + bent sub. 1.6

Wear in Casing The general procedure for reducing/minimising wear on casing has centred around minimising cont act by the use of drillpipe rubbers and by controlling dog legs below recommended limits. In deviated wells in particular, casing wear can be a serious problem, possibly resulting in complete failure of that string. The wear can be reduced significantly be reducing the total number of rotations in the casing by the use of a downhole motor. Drillpipe Rotations = 60 RP P

R F P

= = =

rpm footage penetration rate

Therefore, the number of rotations can be reduced by reducing the rotary speed of the pipe and also by increasing the penetration rate. 1.7

Excessive Rotary Torque Multiwell platforms have increased the departure required from the platform to optimise drainage of a field. This leads to increased hole angles for a well and together with high dog legs which may be present, tends to increase the surface torque required to drill the well. In some cases torque has been so high that the rotary table can no longer be rotated. In this case downhole motors can be employed to provide torque directly at the bit to allow the well to be drilled.

1.8

Selection of Type of Mud Motor Consideration should be given to the following: 1. 2. 3.

Hole size. Bit type, e.g. roller cone, PCD, diamond. Hydraulics limitation.

Tables 2 to 11 provide performance data for three of the major manufacturers’ motors. 1.9

Hole Size The motor should be able to handle flowrates suitable for hole cleaning. Some motors, such as the Drilex D950, incorporate a hollow rotor which may be used as a bypass to allow more flow through the tool, the amount of flow through the bypass is controlled by the use of a bit nozzle at the top of the motor. Comparing the data from Table 8 for the D950 with that in Table 12, one can see that an increase in flowrate of 150 gpm can be achieved by using a 1/2” nozzle. It is important to remember that unless otherwise stated on the performance chart, the figures quoted are those for the tool with the nozzle blanked off. The motor should also be capable of providing enough torque at the bit. The manufacturer’s quoted maximum operating torque is at ± 10% fluid of the slippage between rotor and stator. The stall torque is approximately 50% greater than the manufacturer’s recommended maximum torque. At stall torque, fluid slippage is 100%. Operating the tool above the maximum recommended torque will cause undue wear on the stator.

BP EXPLORATION


Section

:

1630/GEN

Rev.

:

3 (8/90)

Page

:

5 of 16

MUD MOTORS

Bit Type As roller cone bits require less rpm than PDC or diamond bits, their use with PDM’s was limited until the multi lobe low speed motors were developed. As the rotational speed of the motor is solely dependent on the flowrate, a tool which matches hole cleaning with rotary speed is essential.

1.11

Hydraulics Limitations The motor must be compatible with the available pump hydraulic horsepower and it is important to remember that a motor will consume some of the hydraulic horsepower normally available for the bit. Therefore, it is necessary to select a motor which will still allow adequate hydraulic HP at the bit even when operating at maximum torque. It must be remembered that when using a motor resulting in high system pressure losses, the constant application of high pressures may lead to a higher incidence of power end failures.

1.12

Mud Motor Procedures 1.

Checking the Mud Motor Before tripping in, the motor should be tested on the rig floor prior to installing the bit.

2.

a)

Set motor in slips and install safety clamp.

b)

Test bypass valve by pressing the piston down to the internal stop. Release the piston and check its reset.

c)

Connect the kelly and lower the motor until the bypass valve is below the table. Secure with rig tongs.

d)

Start the pumps at ± 10% of maximum flow and check bypass is operating. Increase flowrate until bypass valve closes and make a note of flowrate. Pick up the motor until the drive sub is visible to check motor operating. Lower the bypass valve back below the table prior to turning off the pumps.

Drilling with the Mud Motor All mud motors are subjected to a maximum differential pressure which, if exceeded will result in rapid stator and bearing wear. After reaching bottom with the PDM, the following procedure should be followed: i)

Record off bottom pressure at desired pump rate.

ii)

Set the bit on bottom and gradually set down weight until the desired differential pressure is achieved.

Note: As WOB is applied, the standpipe pressure will increase. This increase is known as the differential pressure and should not exceed the recommended maximum if bearing life is to be maximised. As the bit drills off the differential pressure will decrease. iii) When a suitable WOB is reached, drilling is best continued using the pump pressure gauge as a reference for maximum performance. As the bit speed is dependent only on the flowrate, the bit speed will remain constant as long as the pump rate is kept constant. iv) A sudden rise in differential pressure above the average level indicates stalling. If this happens, pick up off bottom and allow the motor to re-start prior to applying weight to the bit.

BP EXPLORATION

DRILLING MANUAL

:

1630/GEN

Rev.

:

3 (8/90)

Page

:

6 of 16

MUD MOTORS NAVI-DRILL MACH 1

FIGURE 1

BY-PASS VALVE

ROTOR STATOR

UNIVERSAL JOINTS

Rotor Type Rotor Type

MACH 1 Departmental Motor

STABILIZER

NAVI-DRILL

SUBJECT:

Section

BEARING HOUSINGS

DRIVE SUB

BIT

2179 /149

BP EXPLORATION

:

1630/GEN

Rev.

:

3 (8/90)

, , , , , , ,

DRILLING MANUAL

Section

SUBJECT:

Page

:

7 of 16

MUD MOTORS

FIGURE 2

1/2 ROTOR/STATOR RELATIONSHIP

5/6 ROTOR/STATOR RELATIONSHIP

2179 /148

SUBJECT:

BENT SUB ASSEMBLY

Bent Sub Angle

5" Dyna-Drill Tool

6 1/2" Dyna-Drill Tool



12" Dyna-Drill Tool Deflection Angle

1° 1 1/2° 2°

6"

3°30' 4°45' 5°30'

8 1/4"

2°30' 3°30' 4°30'

9 7/8"

2°30' 3°45' 5°00'

13 1/2"

2°00' 3°00' 4°30'

17 1/2"

2°00' 4°00' 5°30'

1° 1 1/2° 2° 2 1/2°

6 1/4"

3°00' 3°00' 5°00' 5°45'

9 7/8"

1°45' 3°30' 3°45' 5°00'

10 5/8"

2°00' 2°30' 4°15' 5°30'

15"

1°45'

22"

2°00' 3°15' 4°00'

1° 1 1/2° 2° 2 1/2°

7 7/8"

2°30' 3°30' 4°30' 5°30'

10 5/8"

1°15' 2°00' 3°00' 4°00'

12 1/4"

1°45' 2°30' 3°30' 5°00'

17 1/2"

26"

1°45' 3°00' 3°30'

3°45' 5°00' 1°15' 2°15' 3°00' 4°30'

1630/GEN

Hole Size

:

Deflection Angle

Section

Hole Size

3 (8/90)

Deflection Angle

:

Hole Size

Rev.

Deflection Angle

8 of 16

Hole Size

:

Deflection Angle

Page

Hole Size

BP EXPLORATION

Predicted Deflection Angle Change for 30m Drilled When Using a Bent Sub/Dyna Drill Combination

DRILLING MANUAL

MUD MOTORS

TABLE 1

SUBJECT:

TABLE 2 - Specifications NAVI-DRILL MACH 1

SPECIFICATIONS (Amer. Std.) Max. Bit Speed Diff. Max. Horsepower Range Pressure Torque Range Efficiency

inch

inch

min.

max.

RPM

PSI

ft-lbs

HP

3 3/4 4 3/4 6 3/4 8 9 1/2

4 1/4 - 5 7/8 6 - 7 7/8 8 3/8 - 9 7/8 9 1/2 - 12 1/4 12 1/4 - 17 1/2

75 80 185 315 395

145 185 370 610 635

125 - 250 90 - 215 90 - 180 75 - 150 90 - 145

640 580 580 465 640

740 1040 2540 4030 6160

11 1/4

17 1/2 - 26

525

1055

70 - 140

520

8850

Thread Connection Bypass Valve

Bit Sub

Length

Weight

max. %

Box Up

Box Down

ft

lbs

17 - 35 17 - 43 44 - 87 58 - 115 106 - 170

65 68 70 70 72

2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg.* 7 5/8" Reg.

16.7 17.4 20.0 23.0 24.6

440 710 1720 2430 4080

118 - 236

73

7 5/8" Reg.

2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg. 7 5/8" Reg. or 6 5/8" Reg. 7 5/8" Reg.

26.6

6070

* Available with 5 1/2" Reg. in USA only.

SPECIFICATIONS (Metric) Pump Rate l/min.

kW

3 3/4 4 3/4 6 3/4 8 9 1/2

4 1/4 - 5 7/8 6 - 7 7/8 8 3/8 - 9 7/8 9 1/2 - 12 1/4 12 1/4 - 17 1/2

280 300 700 1200 1500

550 700 1400 2300 2400

125 - 250 90 - 215 90 - 180 75 - 150 90 - 145

44 40 40 32 44

1000 1400 3450 5450 8350

11 1/4

17 1/2 - 26

2000

4000

70 - 140

36

12000

max. %

Box Up

Box Down

m

kg

13 - 26 13 - 32 33 - 65 43 - 86 79 - 127

65 68 70 70 72

2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg.* 7 5/8" Reg.

5.1 5.3 6.1 7.0 7.5

200 320 780 1100 1850

88 - 176

73

7 5/8" Reg.

2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg. 7 5/8" Reg. or 6 5/8" Reg. 7 5/8" Reg.

8.1

2750

1630/GEN

Nm

:

bar

Weight

Section

RPM

Length

3 (8/90)

max.

Bit Sub

:

min.

Bypass Valve

Rev.

inch

Thread Connection

9 of 16

inch


Max. Bit Speed Diff. Max. Horsepower Range Pressure Torque Range Efficiency

:

Recommended Hole Size

Page

ool Size OD

BP EXPLORATION

Pump Rate GPM

DRILLING MANUAL


MUD MOTORS

ool Size OD

SUBJECT:


SPECIFICATIONS (Amer. Std.) Max. Bit Speed Diff. Approx. Horsepower Range Pressure Torque Range Efficiency

inch

min.

max.

1 7/8 - 2 3/4 2 7/8 - 3 1/2 4 1/4 - 5 7/8 6 - 7 7/8 8 3/8 - 9 7/8 9 1/2 - 12 1/4 12 1/4 - 17 1/2 17 1/2 - 26

20 29 75 100 200 245 395 525

45 720 - 1750 73 550 - 1370 185 280 - 700 240 245 - 600 475 205 - 485 635 145 - 380 740 195 - 365 1055 70 - 140

RPM


Bit Sub

Length

Weight

PSI

ft-lbs

HP

max. %

Box Up

Box Down

ft

lbs

465 695 580 580 580 465 695 465

26 85 385 585 1500 2090 3890 5380

3.5 - 8.6 8.9 - 21 20 - 51 27 - 67 59 - 138 58 - 152 145 - 271 123 - 256

71 75 82 83 86 88 90 90

AW Rod BW Rod 2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg.* 7 5/8" Reg. 7 5/8" Reg.

AW Rod BW Rod 2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg. 6 5/8" Reg. 7 5/8" Reg.

8.9 13.1 19.4 20.0 26.6 26.9 32.8 32.2

49 180 460 840 2160 2800 5200 7300


SPECIFICATIONS (Metric)

bar

Nm

kW

max. %

Box Up

Box Down

m

kg

32 48 40 40 40 32 48 32

35 115 520 790 2030 2830 5280 7300

2.6 - 6.4 6.6 - 16 15 - 38 20 - 50 44 - 103 43 - 113 180 - 202 93 - 191

71 75 82 83 86 88 90 90

AW Rod BW Rod 2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg.* 7 5/8" Reg. 7 5/8" Reg.

AW Rod BW Rod 2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg. 6 5/8" Reg. 7 5/8" Reg.

2.7 4.0 5.9 6.1 8.1 8.2 10.0 9.8

22 80 210 380 980 1270 2360 3310

1630/GEN

170 720 - 1750 275 550 - 1370 700 280 - 700 900 245 - 600 1800 205 - 485 2400 145 - 380 2800 195 - 365 4000 120 - 250

Weight

:

75 110 280 380 760 930 1500 2000

Length

Section

1 7/8 - 2 3/4 2 7/8 - 3 1/2 4 1/4 - 5 7/8 6 - 7 7/8 8 3/8 - 9 7/8 9 1/2 - 12 1/4 12 1/4 - 17 1/2 17 1/2 - 26

RPM

Bit Sub

3 (8/90)

max.

Bypass Valve

:

min.

Thread Connection

Rev.

inch


Max. Bit Speed Diff. Approx. Horsepower Range Pressure Torque Range Efficiency

10 of 16

inch 1 3/4 2 3/8 3 3/4 4 3/4 6 3/4 8 9 1/2 11 1/4

Pump Rate l/min.

:


Page

ool Size OD

BP EXPLORATION

inch 1 3/4 2 3/8 3 3/4 4 3/4 6 3/4 8 9 1/2 11 1/4

Pump Rate GPM

DRILLING MANUAL


MUD MOTORS

ool Size OD

SUBJECT:


SPECIFICATIONS (Amer. Std.) Max. Bit Speed Diff. Approx. Horsepower Range Pressure Torque Range Efficiency

inch

inch

min.

max.

RPM

PSI

ft-lbs

HP

3 3/4 4 3/4 6 1/4** 6 3/4 8 9 1/2 9 1/2 N 11 1/4

4 1/4 - 5 7/8 6 - 7 7/8 7 7/8 - 9 7/8 8 3/8 - 9 7/8 9 1/2 - 12 1/4 12 1/4 - 17 1/2 12 1/4 - 17 1/2 17 1/2 - 26

60 80 170 160 200 240 395 290

145 185 345 395 475 610 900 685

340 - 855 270 - 680 200 - 510 140 - 480 160 - 400 130 - 340 140 - 325 115 - 290

580 580 580 465 465 465 290 465

245 415 1015 995 1475 2280 2210 2990

16 - 40 21 - 54 39 - 98 27 - 91 46 - 113 56 - 148 59 - 137 66 - 165



Bit Sub

Length

Weight

max. %

Box Up

Box Down

ft

lbs

81 85 85 85 87 90 90 89

2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg.* 7 5/8" Reg. 7 5/8" Reg. 7 5/8" Reg.

2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg. 6 5/8" Reg. 6 5/8" Reg. 7 5/8" Reg.

16.7 17.4 23.6 21.7 23.6 24.6 24.6 26.6

400 680 1770 1770 2430 3970 3970 5960

** Available in the USA only.

SPECIFICATIONS (Metric) Pump Rate l/min.

kW

3 3/4 4 3/4 6 1/4** 6 3/4 8 9 1/2 9 1/2 N 11 1/4

4 1/4 - 5 7/8 6 - 7 7/8 7 7/8 - 9 7/8 8 3/8 - 9 7/8 9 1/2 - 12 1/4 12 1/4 - 17 1/2 12 1/4 - 17 1/2 17 1/2 - 26

230 300 650 600 750 900 1500 1100

550 700 1300 1500 1800 2300 3400 2600

340 - 855 270 - 680 200 - 510 140 - 480 160 - 400 130 - 340 140 - 325 115 - 290

40 40 40 32 32 32 20 32

330 560 1375 1350 2000 3090 3000 4050

12 - 30 16 - 40 29 - 73 20 - 68 34 - 84 42 - 110 44 - 102 49 - 123

** Available in the USA only.

max. %

Box Up

Box Down

m

kg

81 85 85 85 87 90 90 89

2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg.* 7 5/8" Reg. 7 5/8" Reg. 7 5/8" Reg.

2 7/8" Reg. 3 1/2" Reg. 4 1/2" Reg. 4 1/2" Reg. 6 5/8" Reg. 6 5/8" Reg. 6 5/8" Reg. 7 5/8" Reg.

5.1 5.3 7.2 6.6 7.2 7.5 7.5 8.1

180 310 800 800 1100 1800 1800 2700

1630/GEN

Nm

:

bar

Weight

Section

RPM

Length

3 (8/90)

max.

Bit Sub

:

min.

Bypass Valve

Rev.

inch

Thread Connection

11 of 16

inch


Max. Bit Speed Diff. Approx. Horsepower Range Pressure Torque Range Efficiency

:


Page

ool Size OD

BP EXPLORATION

Pump Rate GPM

DRILLING MANUAL


MUD MOTORS

ool Size OD

SUBJECT:

TABLE 5 - DYNA-DRILL SLO-SPEED TOOLS Dimensional and Operational Data

7 3/4" F2000S (7/8 Lobe)

9 5/8" F2000S (5/6 Lobe)

3 1/2" 3 1/2"

4 1/2" 4 1/2"

4 1/2" 4 1/2"

5 1/2" 6 1/2"

6 5/8" 6 5/8" (7 5/8" Opt.)

Overall Length

ft (m)

21.4 (6.52)

22.8 (6.95)

19.7 (6.00)

23.1 (7.04)

30.7 (9.36)

Motor Flowrate Range

GPM (LPM)

180 - 250 (681 - 946)

250 - 450 (946 - 1704)

300 - 500 (1136 - 1893)

300 - 600 (1136 - 2271)

800 - 1200 (3028 - 4542)

Max. Input Flowrate W/Nozzle in Rotor

GPM (LPM)

-

750 (2838)

800 (3028)

900 (3408)

-

Bit Speed Range

RPM

110 - 150

100 - 180

80 - 130

75 - 150

90 - 150

Motor Diff. Pressure

PSI (BARS)

250 (17)

455 (31)

540 (37)

860 (59)

450 (31)

Operating Torque

ft-lbs (N-m)

1200 (1627)

2800 (3797)

4000 (5424)

7600 (10,305)

9200 (12,475)

Stall Torque

ft-lbs (N-m)

2100 (2847)

4900 (6644)

7000 (9492)

13,300 (18,034)

16,100 (21,831)

Horsepower

HP (KW)

25 - 34 (18.6 - 25.4)

53 - 96 (39.5 - 71.6)

61 - 99 (45.5 - 73.8)

108 - 217 (80.5 - 161.8)

140 - 245 (104.4 - 182.7)

2

3.5

3

4.75

2.5

200 - 2,000 (14 - 138)

200 - 2,000 (14 - 138)

200 - 2,000 (14 - 138)

200 - 2,000 (14 - 138)

200 - 2,000 (14 - 138)

1025 (465)

1610 (730)

1730 (785)

3290 (1492)

5010 (2272)

Number of Stages Bit Diff. Pressure

PSI (BARS)

Tool Weight

lbs (KG)

1630/GEN

API R API R

Box Up Box Down

:

Thread Conn.

Section

12 1/4 - 17 1/2 (311 - 445)

3 (8/90)

9 7/8 - 12 1/4 (251 - 311)

:

8 3/8 - 9 7/8 (213 - 251)

Rev.

8 3/8 - 9 7/8 (213 - 251)

12 of 16

6 1/2 - 7 7/8 (165 - 200)

:

in. (mm)

Page

Hole Size Range

BP EXPLORATION

6 1/2" F2000S (9/10 Lobe)

DRILLING MANUAL

6 1/2" F2000S (5/6 Lobe)

MUD MOTORS

Tool Size OD

4 3/4" F2000S (5/6 Lobe)

SUBJECT:

TABLE 6 - DYNA-DRILL DELTA 1000 TOOLS Dimensional and Operational Data

5" Delta 1000

6 1/2" Delta 1000

7 3/4" Delta 1000

4 3/4" F 2000*

9 5/8" F 2000*

Hole Size Range

in. (mm)

3 - 4 5/8 (76 - 118)

4 5/8 - 6 (118 - 152)

6 1/2 - 7 7/8 (165 - 200)

8 3/8 - 9 7/8 (213 - 251)

9 7/8 - 12 1/4 (251 - 311)

6 1/2 - 7 7/8 (152 - 200)

12 1/4 - 17 1/2 (311 - 445)

Thread Conn.

API R API R

Walker McDonald NW Thread

2 7/8" 2 7/8"

3 1/2" 3 1/2"

4 1/2" 4 1/2"

5 1/2" 6 5/8"

3 1/2" 3 1/2"

6 5/8" 6 5/8"

13 (3.96)

22.5 (6.85)

21.5 (6.55)

24.8 (7.54)

27 (8.22)

21.4 (6.52)

30.7 (9.36)

Box Up Box Down

150 - 300 (568 - 1135)

600 - 1000 (2271 - 3785)

Bit Speed Range

RPM

790 - 1590

320 - 745

345 - 690

280 - 450

245 - 410

300 - 570

300 - 500


PSI (BARS)

940 (65)

750 (52)

450 (31)

600 (41)

600 (41)

485 (33)

750 (52)

Operating Torque

ft-lbs (N-m)

112 (152)

455 (617)

525 (712)

1340 (1817)

2160 (2928)

750 (1017)

4000 (5423)

Stall Torque

ft-lbs (N-m)

224 (304)

910 (1234)

1050 (1424)

2680 (3634)

4320 (5856)

1500 (2034)

8000 (10,846)

Horsepower

HP (KW)

16 - 33 (11.9 - 24.6)

28 - 65 (20.9 - 48.5)

34 - 69 (25.4 - 51.5)

71 - 114 (53 - 85)

101 - 168 (75.3 - 125.3)

43 - 81 (32 - 60.4)

228 - 381 (170 - 284)

6

5

3

4

4

3.25

5

200 - 1,000 (14 - 69)

200 - 1,000 (14 - 69)

200 - 1,000 (14 - 69)

200 - 1,000 (14 - 69)

200 - 1,000 (14 - 69)

200 - 2,000 (14 - 138)

200 - 2,000 (14 - 138)

145 (66)

530 (240)

1099 (499)

2020 (907)

2825 (1281)

1025 (465)

5010 (2272)


PSI (BARS)

Tool Weight

lbs (KG)

* Medium Speed Motor with Friction Bearing Assembly.

1630/GEN

300 - 500 (1135 - 1893)

:

250 - 400 (946 - 1514)

Section

150 - 300 (568 - 1135)

3 (8/90)

75 - 175 (284 - 662)

:

40 - 80 (151 - 303)

Rev.

GPM (LPM)

13 of 16


:

ft (m)

Page

Overall Length

BP EXPLORATION

3 7/8" Delta 1000

DRILLING MANUAL

2 3/4" Delta 1000

MUD MOTORS

Tool Size OD

SUBJECT:

TABLE 7 - DYNA-DRILL DELTA 500 AND DELTA 500 PLUS 4 TOOLS

7 3/4" Delta 500

9 5/8" Delta 500

12" Delta 500

6 1/2" Delta 500 Plus 4

7 3/4" Delta 500 Plus 4

BP EXPLORATION

6 1/2" Delta 500

Hole Size Range

in. (mm)

6 1/2 - 7 7/8 (165 - 200)

8 3/8 - 9 7/8 (213 - 251)

9 7/8 - 12 1/4 (251 - 311)

12 1/4 - 17 1/2 (311 - 445)

17 1/2 - 26 (445 - 660)

8 3/8 - 9 7/8 (213 - 251)

9 7/8 - 12 1/4 (251 - 311)

Thread Conn.

API R API R

3 1/2" 3 1/2"

4 1/2" 4 1/2"

5 1/2" 6 5/8"

6 5/8" 7 5/8"

7 5/8" 7 5/8"

4 1/2" 4 1/2"

5 1/2" 6 5/8"

Overall Length

ft (m)

19.8 (6.03)

19.9 (6.06)

21 (6.4)

26.5 (8.07)

33.2 (10.1)

23.7 (7.2)

25.2 (7.7)


GPM (LPM)

150 - 250 (568 - 946)

200 - 350 (757 - 1325)

300 - 450 (1135 - 1703)

400 - 600 (1514 - 2271)

700 - 1200 (2650 - 4542)

250 - 400 (946 - 1514)

300 - 500 (1135 - 1893)

Bit Speed Range

RPM

335 - 560

275 - 480

275 - 415

215 - 375

130 - 225

280 - 450

245 - 410


PSI (BARS)

360 (25)

360 (25)

360 (25)

360 (25)

360 (25)

600 (41)

600 (41)

Operating Torque

ft-lbs (N-m)

425 (576)

690 (935)

1130 (1532)

1935 (2623)

6400 (8677)

1340 (1860)

2160 (2928)

Stall Torque

ft-lbs (N-m)

850 (1152)

1380 (1870)

2260 (3064)

3870 (5246)

13,800 (17,754)

2680 (3632)

4320 (5856)

Horsepower

HP (KW)

27 - 45 (20.1 - 33.6)

36 - 63 (26.8 - 47)

60 - 90 (44.7 - 67)

80 - 130 (59.6 - 103)

160 - 275 (119.3 - 205)

71 - 114 (53 - 85)

101 - 168 (75.3 - 125.3)

3

3

3

3

3

4

4

Page

Rev.

150 - 500 (10 - 34)

150 - 500 (10 - 34)

150 - 500 (10 - 34)

150 - 500 (10 - 34)

150 - 500 (10 - 34)

150 - 500 (10 - 34)

150 - 500 (10 - 34)

Section

:

:

:

911 (413)

1582 (718)

2350 (1066)

4350 (1973)

8100 (3674)

1905 (866)

2520 (1168)

14 of 16

3 (8/90)

1630/GEN

DRILLING MANUAL

Tool Size OD

5" Delta 500

MUD MOTORS

Dimensional and Operational Data

Box Up Box Down


PSI (BARS)

Tool Weight

lbs (KG)

Motor Size OD

Motor Ref. No.

Maximum Allowable WOB

Flowrate Operating Range

Bit Speed Range

Maximum Operating Torque

Motor Pressure Drop at Max. Torque

Motor Length

Motor Weight

Top Connection

Bottom Connection

Lobe Configuration

psi

lbs

gpm

rpm

ft-lbs

psi

ft

lbs

Box Up

Box Down

Rotor/Stator

1500

25000

100-250

140-350

1500-1800

800-1000

21.0

800

3 1/2" Reg

3 1/2" Reg

5/6

6 3/4

D675

1500

50000

200-650

55-185

4500-6000

800-1000

24.0

2100

4 1/2" Reg

4 1/2" Reg

9/10

7 3/4

D775

1500

60000

200-650

55-185

4500-6000

800-1000

23.5

2800

5 1/2" Reg

4 1/2" Reg

9/10

8 1/4

D825

1500

65000

200-650

55-185

4500-6000

800-1000

23.5

3200

6 5/8" Reg

6 5/8" Reg

9/10

9 1/2

D950

1500

75000

500-850

110-190

5500-7500

800-1200

24.0

4200

6 5/8" or 7 5/8" Reg

6 5/8" pr 7 5/8" Reg

10/11

TABLE 9 - Drilex Directional PDM Specifications 4 3/4

DIR475

1500

25000

100-250

140-350

8500-9500

650-750

9.9

350

3 1/2" IF

3 1/2" Reg

5/6

6 3/4

DIR675

1500

50000

300-650

85-185

3300-4500

550-650

13.1

1050

4 1/2" Reg

4 1/2" Reg

9/10

7 3/4

DIR775

1500

50000

300-650

85-185

3300-4500

550-650

13.1

1500

5 1/2" Reg

6 5/8" Reg

9/10

TABLE 10 - Drilex Workover PDM Specifications 1 11/16

D170

200

2200

10-22

645-1435

300-380

900-1100

7.4

40

API NC12

API NC12

3/4

2 3/8

D237

200

3200

30-42

580-850

950-1200

900-1100

9.1

100

1 1/4" Reg

1 1/4" Reg

5/6

10.7

240

2 7/8" Reg

2 7/8" Reg

9/10

3 1/2

D350HS

200

7000

40-90

256-576

1950-2650

900-1000

11.8

270

2 7/8" Reg

2 7/8" Reg

7/8

3 3/4

D375

1000

14000

90-150

320-530

4250-5800

900-1000

13.4

364

2 7/8" Reg

2 7/8" Reg

5/6

6 3/4

D675HS

1500

50000

200-400

159-318

1800-2400

800-1000

25.0

2030

4 1/2" Reg

4 1/2" Reg

6/7

7 5/8

D775HS

1500

65000

200-400

159-318

1800-2400

800-1000

25.6

2665

5 1/2" IF

6 5/8" Reg

6/7

9 1/2

D950HT

1500

75000

700-1100

115-180

7200-10000

800-1000

31.5

5000

7 5/8" Reg

7 5/8" Reg

7/8

1630/GEN

625-850

:

3000-4000

Section

240-330

3 (8/90)

80-110

:

7000

Rev.

200

15 of 16

D350

:

3 1/2

Page

TABLE 11 - Drilex Speciality PDM Specifications

BP EXPLORATION

D475

DRILLING MANUAL

4 3/4

MUD MOTORS

inches

Max. Bit ∆P

SUBJECT:

TABLE 8 - Drilex Standard PDM Specifications

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MUD MOTORS

TABLE 12 D950 with 16/32" Nozzle Motor Performance Specification

Pressure Differential

Q gpm

850

900

950

1,000

Q l/min.

3,217

3,407

3,596

3,785

100 psi

ft-lbs

1,350

1,350

1,350

1,350

6.8 Bar

Nm

1,830

1,830

1,830

1,830

RPM

139

147

158

169

200 psi

ft-lbs

2,520

2,520

2,520

2,520

13.6 Bar

Nm

3,410

3,410

3,410

3,410

RPM

133

141

151

160

300 psi

ft-lbs

3,610

3,610

3,610

3,610

20.4 Bar

Nm

4,890

4,890

4,890

4,890

RPM

127

135

146

155

400 psi

ft-lbs

4,580

4,580

4,580

4,580

27.2 Bar

Nm

6,210

6,210

6,210

6,210

RPM

118

127

139

149

500 psi

ft-lbs

5,420

5,420

5,420

5,420

34.0 Bar

Nm

7,340

7,340

7,340

7,340

RPM

107

116

132

141

600 psi

ft-lbs

6,150

6,150

6,150

6,150

40.8 Bar

Nm

8,330

8,330

8,330

8,330

RPM

95

105

127

126

700 psi

ft-lbs

6,850

6,850

6,850

6,850

47.6 Bar

Nm

9,820

9,820

9,820

9,820

83

95

114

129

RPM

For continuous drilling operations, it is recommended that the differential pressure increase between on and off bottom is limited to 500 psi.

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MUD MOTORS USED WITH MWD TOOLS

USE OF MWD WITH MUD MOTORS Surveying using conventional wireline magnetic single shot equipment is time consuming and unreliable in high angle holes. The chances of drill pipe sticking are enhanced due to lack of string movement during running/pulling survey barrels. MWD tools can be successfully used with mud motors and the following is an example of the combination of the two tools and a description of the method of orientation.

1.1

Test mud motor at surface.

1.2

Make up mud motor and MWD assembly: Bit - Mud Motor - Bent Sub - Pony Non-MAG Drill Collar - MWD Tool - NMUBHO Sub - 2 Monel Drill Collars - rest of assembly as required.

Notes:

1.3

a)

The length of the Pony NMDC should be such as to give a minimum length of 7.6m of monel below the magnetic sensor of the MWD tool.

b)

During kick-off and sidetracking, the MWD collar may be made up directly on top of the bent sub. The initial orientation and kick-off will be performed using the MWD tool in highside mode. When the deflection BHA is pulled to continue the build-up in rotary mode, the MWD collar will be positioned in its normal place and the kick-off section re-surveyed prior to drilling ahead.

Orienting (where manual input is required) Measure the difference between the bent sub scribe line and the MWD scribe line in a clockwise direction. Use the following formula to calculate the degrees (right) difference. Difference (in inches) (clockwise) x 360 = deg right from bent sub MWD circumference (in inches) e.g.

Teleco Circumference = 30"

Teleco Scribe Line

Diff. = 7.5"

7.5 x 360 = 90° 30

Therefore, when MWD tool display (which is hi side mode) shows 90° bent sub is hi side (360°).

BENT SUB SCRIBE LINE

1.4

Run in hole and proceed as per normal tool run. Bench mark as per standard surveying instructions.

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REBEL TOOLS

The Rebel Tool is one of the most under-used and underestimated directional aids. If the task and the tools’ capabilities are properly identified, smooth azimuth changes can be effected. The most prominent drawback in using rebel tool assemblies is their tendency to drop angle. The connections are reg. box/box. 1.1

When to Use the Rebel Tool For azimuth changes, left or right of hole direction, when hole inclination can be sacrificed. In 12 1/4” hole or smaller. The tool works best in gauge hole. When drilling with oil based mud gauge holes are drilled and predictible, repeatable results can be obtained when using the rebel tool.

1.2

Principle of Tool Two paddles are rigidly connected at fixed angles to either end of a shaft. The shaft is held onto the body proper of the tool by 2 bearing blocks. The shaft is free to move around an arc of some 40 degrees, within the bearing blocks. As the tool is rotated in the borehole the upper paddle (furthest from the bit) during one revolution will be, at one point, on the low side of the hole. In this position the upper paddle will be close to and touching the body of the rebel tool. As both paddles are rigidly connected by the shaft, the position of the lower “steering” paddle is directly determined by the upper paddle. The geometry of the paddles is arranged such that when the upper paddle is on the low-side of the borehole, the lower paddle, nearest the bit, will be “sticking out” from the main body of the tool. In this position the lower paddle forces the bit to the right or to the left, depending on how the tool is dressed. Thus for 1 revolution of the tool, the lower paddle will “hammer” the bit one blow sideways. The end result is to effect a gradual, smooth change in azimuth.

1.3

Checking and Maintenance of Tool The tool will be supplied from rental companies already dressed for right or left hand turn. Always insist that both right and left turn paddles are supplied. The condition of the single replaceable stabiliser on the lower end of the tool should be completely unworn. If the stabiliser is worn replace it before making up the assembly. Order a spare stabiliser as a back-up. The hardfacing on the lower paddle should be in an “as new” condition. If the hardfacing is worn or missing the paddle should not be run. The shaft should be free to move within the bearing blocks and absolutely no movement of the paddles on the shaft should be evident.

1.4

Identification of Right and Left Turn Paddles and Shaft

Note: It is possible to dress the rebel tool with the paddles upside-down and also to incorrectly identify right and left hand paddles. Don’t assume that the tool is correctly dressed just because it arrives freshly painted from the rental company. Left hand walk paddles are LONG and right hand walk paddles are SHORT. This is the reason for sending out BOTH right and left hand walk paddles to the rig. An immediate, indisputable comparison of both types can be made. The upper paddle (furthest from the bit) is always thinner in section and more curved than the lower paddle. Hardfacing is welded onto the lower paddle to reduce wear as it “hammers” against the wellbore. As a final check, once the tool is dressed, roll the tool on the catwalk until the upper paddle (furthest from the bit) is underneath the body of the tool, i.e. on the “low side of the hole”. With the tool in this position, the position of the lower paddle (nearest the bit) can be clearly seen, i.e. the paddle will either be to the right or to the left of the bit direction. 1.5

Changing Paddles and Shaft To remove the shaft, carefully mark the two bearing block caps. They are not interchangeable and should not be mixed. All the components securing the shaft to the main body are not interchangeable and should be carefully marked and replaced in their identical “as shipped” positions. The spring steel retaining pins are not positioned horizontally into the block caps but are fixed at an angle. This should be taken into account when removal/replacement is done. The paddles and shaft assembly are not

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REBEL TOOLS

field serviceable. When bolting the shaft back onto the main body, coat the bolts with copper based lubricant and carefully torque up.

Note: The Allen screws and washers used to bolt the bearing blocks are only used once and must be replaced for re-assembly. 1.6

Operating Parameters Consider the rate of turn as being dependent on the number of “hammer blows” per foot of formation drilled. The quicker the penetration rate, the smaller the number of “hammer blows” per foot drilled and hence the slower rate of turn. Therefore WOB, RPM, hydraulics and formation drillability are all factors affecting rate of azimuth change. Typically for running in 12 1/4” hole, directional assembly could be: Bit, Rebel Tool, 1 x 8” Monel DC, 18’ x 8” Short Monel DC, MWD Tool, 12 1/4” Non Mag Stab, 2 x 8” Monel DC, 12 1/4” String Stab, 3 x 8” DC, etc. Depending on bit type, annular velocity required and formation, drilling parameters fall into the following ranges: WOB 30-40, RPM 80, GPM 650 Care must be exercised when handling the rebel tool. The paddles can be damaged on the catwalk with careless handling and/or slinging. Run the assembly carefully through the BOP’s and wearbushing. When running the assembly to bottom always wash or lightly ream the last 60 ft to bottom. At the end of the run, bear in mind when pulling out of the hole that the paddles may be sticking out slightly from the main body. Thus limit any overpull to hole drag + 5000 lbs max. Pulling the assembly back into the casing shoe should be done with extreme care with the compensator, if available, unlocked.

1.7

Achievable Rates of Turn Analysis of 40 separate rebel tool results show that up to 3 deg/100’ of turn is possible. For well planning purposes 1.75 deg of either right or left turn can be achieved. The overall tendency for rebel tool assemblies is to drop angle - anything up to 1.5 deg/100’ but they can also build angle - average build being 0.5 deg. For well planning purposes the drop/build ratio can be estimated at a 70/30 split.

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REBEL TOOLS

Securing Thrust Pin Block / Spring Pin End Outboard Bearing Block Left Walk Arm Assembly or Right Walk Arm Assembly

Inside Split Bearing Block / Cap Screws / Lock Washers

Body Specifications Body OD Length Bore Weight (lbs) Connection, A.P.I. Reg Box Down

Inside Split Bearing Block / Cap Screws / Lock Washers

4 13 /16 " 8' 1 3 /16 " 470 3 1/2 "

5 3/ 4 " 10' 1 1 /4 " 800 4 1/2 "

6 5/ 8 " 11' 1 9 /16 " 1250 4 1/2 "

7 5/ 8 " 13' 1 7/8 " 1850 5 1/2 " 6 5/ 8 "

8 7/ 8 " 16' 2 1/4 " 3600 6 5/ 8 " 7 5/ 8 "

BOTTOM PADDLE

TOP PADDLE

Left Walk Arm Assembly or Right Walk Arm Assembly

End Outboard Bearing Block Securing Thrust Pin Block / Spring Pin

Driltrol Stabilizer Blade

2233/6

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TURBODRILLING PROCEDURES

TUBRODRILLING 1.

GENERAL Turbodrills are classified in two main groups: 1. 2.

Short side tracking/kick off turbodrills. Straight hole turbodrills.

The following notes are applicable to straight hole turbodrills only. Straight hole turbodrills are supplied in multi sectional form. Depending on type and application, they will comprise one bearing section plus a back up bearing section and either one, two or three turbine motor drive sections. The separate sections will be made up on the rig floor prior to RIH. All relevant crossovers will also be supplied with the equipment. When used in deviated wells, their application will normally only be in the tangent sections. Straight hole turbodrills are constructed so as to enable the integral stabilisers to be adjusted to allow for building, holding, or slightly dropping hole angle, as well conditions require. The tendency of a turbodrilling assembly is to gradually turn the hole direction to the left, therefore an additional advantage of turbodrilling is that long correction runs may be made without having to resort to conventional methods of correction. It is generally accepted that the amount of left hand turn can be controlled by varying the bit/nearbit stabiliser configuration: the longer the gauge length, the greater the amount of turn. 1.1

Recommendations Prior to Turbodrilling If rotary drilling is to be carried our prior to turbodrilling, a stiff assembly should be run, otherwise it may be difficult to get the rigid turbodrill assembly to bottom. Ensure a DP wiper is used on the trip out prior to running the turbodrill, and on the trip in with the turbo. Remove the wiper prior to drilling. With the elevated pressures and discharges normally associated with turbodrilling, it is essential the pumps are checked and any suspect parts, i.e. piston/liners/valves/seats, and liner or valve cap gaskets are replaced prior to commencement of turbodrilling. Deficient pump condition will at best, stop the drilling operation, and could lead to bit failure. Liner size/pressure rating is usually the limiting factor on discharge volumes during a turbodrilling operation, as power output is a function of volume pumped. However, lower pressures, and consequently discharge volumes, can be used if, for some reason, “on location” conditions demand this, but performance figures will also be reduced. If coarse LCM, e.g. nut plug, has been used in the mud system, this should be cleaned up before commencement of turbodrilling. A junk sub should be run on the last rotary assembly to avoid any possible damage to the diamond bit.

1.2

Information Required Prior to Turbodrilling 1. 2. 3. 4. 5.

Maximum and minimum circulating rates. Pump discharge volume, pressures and HHP. Calculated circulating pressures when on bottom. Maximum pull and torque capacity of turbine. Maximum WOB for bit type.

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Recommendations During Turbodrilling Circulating subs are supplied with the equipment and are run immediately above the turbodrill. However, in deviated hole work, consideration as to the method of surveying could affect the use of this item in the BHA. When used, a circulating sub is solely for the purpose of circulating LCM. Harsh LCM such as walnut shells or their derivatives should not be present in the mud system as this can lock the turbodrill and make it inoperable. If lost circulation problems are encountered fine mica pills can safely be pumped. Since the mud is lubricating the bearings, the life of the turbodrill can be reduced considerably by high sand/solids content. Maximum use should be made of solids control equipment. Should any section of the turbodrill be changed at the Company Representative’s insistence, when the previously run unit is suitable for re-running, a part overhaul charge may be made for each section changed.

1.4

Checks Prior to Picking Up Turbodrill Immediately the Turbodrill Operator arrives on location, he should check the equipment out as per the Dispatch note. When a turbodrill is in operation, a filter screen is used in the top joint of drill pipe in the string. Two filters are supplied so that no time is lost during connections for cleaning. The filters should fit comfortably inside the drill pipe tool joints.

Note: The hydril retrievable dart will not pass through these filters and, therefore, well control considerations must be discussed prior to installing any filters in the drill string. An alternative to placing filters in the drill string is to install finer filters in the mud pump discharge lines. When it is planned to use a circulating sub, the drop ball should be able to pass through any restrictions in the string, e.g. filter screens, jars, dart sub, etc. All dimensions must be recorded, complete with drawings, in the assembly book, i.e. lengths, OD’s and ID’s and also the length and gauge of the turbodrill stabilisers and the diamond bit. 1.5

Turbodrill Pick Up and Running Procedure The turbodrill body connection make up torque is critical, and every care should be taken to ensure that all rig equipment, tongs, gauges, etc. are functioning correctly. Excessive pipe dope should not be used. Every opportunity should be taken to rotate the shafts during pick up to ensure subsequent smooth operation. After all connections have been torqued up, the thrust bearing clearances should be measured and the shaft turned. Pick up kelly or circulating head and function test the turbine, recording pressure/strokes relationship prior to making up bit/nearbit stabiliser. Re-measure the shaft thrust bearing clearances (these will be the definitive clearances), make up bit/nearbit stabiliser and RIH. Proceed carefully when running in open hole. If reaming is required, the bit is liable to stick and considerable caution should be exercised during this operation. Reaming over excessively long intervals is not recommended as bits may become damaged, and the rate of turbodrill thrust bearing

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wear is higher than in a normal drilling condition. Reaming should only be carried out with a low WOB (0 - 3000 lb) and a maximum of 85% of the normal flowrate. The bit pattern should be drilled in with as light a weight as possible. Operating characteristics should be monitored continuously and these are mainly:a) b) c) d)

Volume and Pressure. String RPM / Rotary Table Torque. Weight on Bit and Stall Weight. Pressure Drop Through Bit.

Tabulate the above records throughout drilling. If for any reason circulation alone is to take place, e.g. sampling, prior to surveys, washing down, etc., the thrust bearings are subject to the entire hydraulic thrust and full shaft runaway speed rpm. To avoid undue wear on the bearings and possibly other problems, the discharge should be reduced as compared with that used when drilling. A reduction of 50% compatible with the safety of the well is recommended. After each trip the following items should be checked:a) b) c) d)

Bit and Nearbit Stabiliser. Stabilisers. Thrust Bearing Section Wear Clearances. Assembly Marks on Body of Turbodrill.

At the end of a turbodrilling operation the sections should be flushed through with water and oiled immediately they are pulled out of the hole. 1.6

Pressure Drop Through Bit - Lower Bearing Leakage The pressure drop through the bit on the bottom of the hole is generally indicated by the manufacturer in terms of discharge and mud weight. An increase in pressure drop lowers the power input to the turbodrill - for a given surface pressure - and also causes an increase in the volume of fluid passing through the turbodrill’s lower bearing, thus decreasing the volume of mud passing across the face of the bit. The bit T.F.A. must be checked to ensure it is compatible with the turbine. In hard formation, the pressure drop should normally be as low as possible. In soft rock, e.g. marl and clay, it should be high enough to permit satisfactory removal of cuttings. With present-day turbodrills, the pressure drop caused by the bit should not exceed the values given below. Nominal OD of Turbodrill

5”

7 1/4”

9 1/2”

Maximum pressure drop through the bit at nominal discharge with clean water

150 psi

450 psi

450 psi

The probable circulating rate, and consequent surface pressure, must be calculated before the turbine is run.

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FISHING 1.7

Freeing the String - Jars A jar should always be run in the string. Unlike rotary drilling, the shaft of the turbodrill is not fixed to the body and therefore the bit cannot be freed by simply rotating the pipe. A special operation is needed, as described in the subsection below. Turbodrills are not affected by short periods of jarring but after a period of several hours, the unit should be pulled.

1.8

Pull, Push and Torque The techniques used to free a stuck turbodrill body are the same as those used in rotary drilling. The Turbodrill Operator will be able to furnish the maximum pull, push and torque loads which may be applied to the equipment. If the load ranges permitting immediate re-use are exceeded, then the turbodrill should be backloaded, together with a record of the loads to which it was subjected. Torque loads may be applied, in the normal manner, when the turbodrill body is stuck. However, to free a stuck bit, the required number of steel balls to be dropped to key the top of the shaft with the body will be supplied by the turbodrill operator. With the shaft keyed to the body, torque applied at the surface is transmitted to the bit. Permissible pull loads on 7 1/4” and 9 1/2” units are usually higher than the maximum permissible tension in the drill string.

1.9

Oil Plug Oil plugs can be used, as with rotary drilling.

1.10

Acidising Acidising is feasible with turbodrills : the resistance of the turbodrill to acids is at least as great as the resistance of the pipe. Full details should be recorded in the turbodrilling report, including (a) amount, concentration and type of acid, and (b) time of exposure. Turbodrills subjected to acid should be carefully washed down on surface. Depending on the acidisation conditions, the Operator may recommend a factory inspection prior to re-use.

1.11

Back-Off Unscrewing the drill string by a “back-off” requires that the body of the turbodrill should not be free to rotate. This is when the body itself is stuck. When the bit is stuck but the body free, then the unit may be locked by dropping balls down the string, as indicated in the Pull, Push and Torque section.

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TURBINE FILTER, HANDLING TOOL AND CIRCULATION SUB

ØA FILTER DIMENSIONS

FILTER

PIPE HANDLING TOOL ØA ØC

ØB ØC D

mm

127

89

in

5

3 1/2

mm

1045

74

in

41.14

2.91

mm

67

41

in

2 5/8

1.61

mm

83

50

in

3 1/4

2

mm

900

600

in

35 1/2 23 5/8

TOOL JOINT

D

CIRCULATION SUB

ØB

CLOSED

OPEN

2179/90


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SIDETRACKING PROCEDURES

BASIC PRINCIPLES There are several simple, but crucial, conditions which must be met before a successful normal (ie not an open-hole type) sidetrack can be completed:

2.

1.

A uniform, homogeneous plug of a hardness as comparable as possible to the formation hardness must be set. If it is harder than the formation all well and good, but this is generally rare except in soft ‘top-hole’ formations, and the basic function of the plug is usually to provide support for the sidetrack assembly to lean against to guide it into the formation once a ledge has been started, ie to extend the ledge laterally.

2.

The sidetrack point must be chosen after looking at a mudlog of the original hole showing specifically formation and ROP data. A 30' to 50' section (hole size/condition dependent) is usually required to sidetrack without producing an unacceptably high dogleg.

3.

A suitable bit must be chosen that will ‘get off’ given the formation hardness/abrasiveness, severity of the motor bend angle set and the expected time to be taken – ie it should not lose its edge too quickly.

4.

The assembly should be selected depending on formation hardness, cement integrity and bit type chosen. It is always advantageous time-wise to use an assembly that can dress-off, sidetrack and drill ahead in one run.

SETTING THE CEMENT PLUG In order to facilitate a successful normal (not open-hole) sidetrack, the first and most crucial step is to set a good, homogeneous plug. The success of this is dependent on several factors and ideally the cement should have reached its full compressive strength within 24 hours – a plug that requires longer than this to cure will rarely provide a solid enough base, especially if formations are hard. Spacer and slurry volumes should be large enough to clean up the hole (remove mud and filter cake), minimise contamination and then provide sufficient length of good plug to aid the sidetrack procedure over the chosen interval where the attempt will be made. The mud type, compatibility with the cement, hole size and hole inclination are all factors with an important bearing on being able to succeed in this. If there is any doubt, larger volumes have little potential downside. The cement plug required for sidetracking must always be of better quality than that expected to, for example, set casing or abandon a hole. It has to fulfil other requirements.

3.

TESTING THE PLUG The best procedure is always to use a dedicated dress-off assembly to do this, particularly if there is a history of poor cementation in a particular mud type, cement type, field, hole angle, hole size, formation etc. The parameters whilst dressing off should be kept constant to identify both overall hardness and uniformity. To confirm the latter, it may be necessary to drill up a fair section of cement. The temptation is always to stop immediately the plug firms, but this may hide its true integrity – there could be hard and soft stringers within the cement. Normally, 15k WOB and 60 to 80 RPM with a mill-tooth bit should drill at 25m/hr maximum over one or two singles, but the Directional Driller would have his own preferential parameters to gauge whether the plug is good enough. If this is significantly lower than the formation ROP under comparable parameters, then sidetracking will be relatively easy, but this is rare.


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Ideally the sidetracking/drill ahead assembly may be used if there is enough information and experience in the area to confidently predict a decent plug – this obviously gives a major time-saving over the dress-off only option. Depending on the assembly/bit combination (PDC/TCI/Mill-tooth and motor/rotary), the above parameters would require modification. Again, the Directional Driller will need to decide which parameters to use and whether the plug integrity is sufficient to allow him to proceed with the sidetrack. If the plug is suspect in any way, it should be drilled out and reset. Time is often lost making an attempt that stood little chance of success. As a final, often crucial, check the drilled cement samples should always be collected and analysed by the mudloggers to confirm their hardness. 4.

SIDETRACKING ASSEMBLIES There are four potential assemblies that can be used to sidetrack. Each has its own advantages and disadvantages, and the Directional Driller should choose that best suited to ‘get off’ given formation type/hardness, desired toolface set and plug condition. This will also be governed by what the plan (well trajectory) might be once the hole has been successfully sidetracked. The first step is obviously to sidetrack and whether or not a ‘drill ahead’ assembly may be used for this purpose will depend on the Directional Driller's judgement on what can be achieved overall. The following are assemblies that could be used in order of preference under most conditions:

4.1

Steerable (Stabilised) This is generally the first choice option as it can dress-off, sidetrack and drill ahead in one pass. It is probably not ideal for any single step of the operation, but will most often do all sufficiently well to ensure success. The choice of bit, bend angle and motor type will depend on all the considerations noted earlier. This assembly does rely fairly heavily on the plug integrity to give the motor stabiliser something to lean against to extend the sidetrack into the formation. Hanging up can be a problem, especially when the final ‘jump off’ into formation occurs. Consists of bit, motor c/w U/G stab and ABH (adjustable bent housing) set 1 to 1 1/4 deg, Pony NMDC, U/G stab, MWD, U/G stab, etc.

4.2

Steerable (Slick) In problem formations, where hanging up can occur or when plug integrity is suspect (mimicking openhole sidetracks), this assembly, normally with a larger bend angle, will give a greater chance of success. Often, a slick adjustable assembly is also that preferred to drill ahead (and dress cement) and this type is almost interchangeable with the first option. It may also be run with large non-rotatable bend angles to give maximum lateral force and bit tilt to ensure the sidetrack, but obviously the dogleg potential is high and care should be used, especially once into the formation. Normally consists of bit, motor, slick c/w 1 to 1 3/4 deg ABH, Pony NMDC, MWD, etc. At smaller bend angles this also relies on reasonable plug condition to provide support to extend into the formation as for option 1.

4.3

Bent Sub Not often used in smaller hole sizes or harder formations these days, this assembly has been superseded by options 1 and 2. This relies solely on lateral force whereas those above rely on a combination of both lateral force and bit tilt. Normally consists of bit, motor, bent sub, stab (if desired), Pony NMDC, MWD, stab (if desired), etc.

4.4

Pendulum Run with either PDC or Rockbit, this can sidetrack in softer formations, but the plug generally needs to be as firm or firmer than the formation at the sidetrack depth. Normally this confines its use to shallow (eg tertiary and younger age) formations. Pendulum length is critical and to maximise it with a PDC, for example, can negate the very feature that the technique uses in that the belly produced allows the gauge pad to take all the lateral force, effectively lifting the cutters away from the wall. Once in formation, the assembly’s directional tendency will increase and it should be used with caution, unless the well plan requires drop.


SUBJECT:


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Under normal circumstances options 1 and 2 are the assembly types to consider. Any bit can be matched to them, but the choice is formation and assembly dependent. Ideally the assembly should allow for rotary drilling after getting off to allow surveys to confirm the result and what is required as follow-up. A sidetracking bit should be considered if there are any potential problems – they are made for a specific purpose and will ensure success in harder formations, open-hole sidetracks, etc. If the hole is lost close to a casing shoe, a whipstock should be seriously considered. Current technology includes ‘one-trip’ systems which will often provide a successful sidetrack in less time than it would take to set a plug, allow it to harden and then time-drill off it. Whipstocks do introduce fairly high doglegs over a short interval and their use will depend on whether this is acceptable given the subsequent well trajectory – ie its use close to surface is not generally recommended. 5.

SIDETRACKING PROCEDURES The choice of toolface set is important and depends on the follow-up plan and what needs to be achieved. All things being equal (good plug, amenable formation, etc) it should be such that little orientation is required to correct the trajectory after the well is sidetracked. Another factor to be considered is hole condition – if, for example, the hole was lost due to collapse, it may not be wise to go low side as there is probably a fair chance the sidetrack point could collapse later. There are few hard and fast rules as to how fast a sidetrack should be initiated. A general rule of thumb is that the initial ROP should be 10 to 20% of that made whilst drilling the original hole with a comparable bit. This allows the assembly to cut as much of a ledge as it can and extend it into the formation. Once the first 2 to 3m has been made then progress should be picked up in stages. At the same time, formation samples should be caught and percentages (formation vs cement) will indicate the rate at which the ROP should be increased. Generally, once 70% formation is noted then the sidetrack should be considered successful and it is then time to consider rotating ahead or pulling the assembly for one to drill ahead as per the well plan.

6.

CONCLUSION As long as a decent plug has been set, the correct sidetrack point chosen and the most efficient assembly/bit combination has been run for the job, there is no reason why the sidetrack should not succeed first time, every time and drilling continue without the need for an assembly/bit change. Only special circumstances as detailed above will require further consideration.

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SUSPENSION AND ABANDONMENT PROCEDURES

GENERAL Prior to the suspension or abandonment of an exploration well, permission must be obtained from the Department of Energy, following procedures laid down in CSON No. 12. In the case of abandonments, it is a requirement that the seabed has been surveyed and certified clear of debris within a 70m radius of the wellhead (see 3.6). In the case of suspended wells, the wellhead must be marked with a buoy if the water depth is less than 45 metres. All necessary contact with DEn will be made by the DES/SDE in town. In addition to the requirements of CSON No. 12, there is an additional requirement that the MOD is provided with advance notice of underwater explosions. This follows their concern that submarines have experienced unidentified explosions when operating in the North Sea.

Telex notification of explosive wellhead cutting is to be sent at least 24 hours prior to the operation. This telex is to be sent directly from the rig and copied to the Drilling Superintendent. 2.

WELL SUSPENSION

2.1

An exploration well may be suspended for one of the following reasons:

2.2

2.3

1.

The well has not been completed, but the rig has to move off location for some reason.

2.

The well has been successfully drilled but has not been fully tested.

3.

The well has been drilled and tested and may possibly be required in the future as part of a field development.

In all cases the main requirements of the well suspension (sometimes called temporary abandonment) are: 1.

To leave the well in a safe condition downhole, such that if the wellhead is accidentally damaged or removed, the well will retain pressure integrity and will not flow.

2.

To allow the well to be re-entered at a subsequent date and a BOP installed without recourse to repair work.

3.

To leave a well in a condition such that subsequent abandonment can be carried out by a Diving Support Vessel which will be able to recover the wellhead without rig intervention (this means that there will be no requirement to cement off casing annuli when the casing strings are cut).

To cover the condition 2.2.1, it is usual to plan the well with the following features: a)

Fluids left in the casing annuli are treated with biocide and corrosion inhibitor (no requirement for this with OBM).

b)

Top of cement in casing cementation is programmed so as to cement all potentially productive formations.

c)

Permeable formations of different geological ages are (usually) isolated by cement.

d)

Formations having different pressure regimes are isolated from each other.

e)

Silica blend cement is used where temperature effects may cause long term degradation of neat class G cement.

To cover 2.2.2, a corrosion cap is run to protect the wellhead and its sealing areas.

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In the plug back operation for a suspended well the following general guidelines apply: a)

If the well has been tested then the different test intervals will normally be separated from each other by bridge plugs or by both bridge plugs and cement plugs if space allows.

b)

A cement plug will be placed above the topmost sand unit (or perforated zone) with a minimum acceptable depth of 30m above the unit or zone. This plug will be tagged and weight tested, or pressure tested to a value of 1000 psi above the formation intake of the tested unit.

c)

Where there is an open hole section, a cement plug will be placed across the casing shoe, 50 75m above and 50 - 75m below the shoe. This plug is normally tagged. Formations in the open hole section of different geological age are normally isolated by cement plugs. Where the open hole section is relatively short and small diameter (8 1/2”), it is common practice to fill the entire section with cement. If the condition of the open hole precludes running pipe into it, then a bridge plug should be set 30m above the shoe with 50m of cement above the bridge plug.

d)

A bridge plug will normally be set in the production casing at approximately the same depth as the intermediate casing shoe, and a 100m cement plug set above this. If the open hole cement plug is extended to cover the shoe, then this bridge plug is to be set higher up (below surface cement plug).

Note: Refer to Table 1 for a summary of the minimum cement plug requirements. 2.5

The well will be suspended with a fluid (either mud-inhibited if required - or brine) of sufficient density to give a minimum 200 psi overbalance on known formation pressure with the BOP/riser removed.

2.6

General Procedures 1.

Refer to Section 3600/GEN for details on setting cement plugs.

2.

Prior to commencing the plug-back, ensure that the well is circulated clean of produced fluids.

3.

When tagging plugs use a minimum bit weight of 10,000 lbs and slow pump to ensure that the plug will not wash away. If the plug is soft, it may be necessary to WOC prior to tagging again. A casing scraper assembly can be used to tag the plug if it is planned to set a bridge plug higher in the casing string.

4.

Prior to running a bridge plug a wireline gauge ring should be run. If a casing scraper is run to tag a lower cement plug, then scrape bridge plug setting depth and cancel the gauge ring run.

5.

After setting the final cement plug, displace the riser to seawater at the wellhead and pull BOP/riser.

6.

Refer to the wellhead manual for procedures when running the corrosion cap. Use the ROV to monitor the procedure and ensure that the wellhead is filled with oil.

7.

Use the ROV to cut the guidewires and attempt to clear the post tops of wire debris.

2.7

A suspended status diagram must be completed by the Rig DE and approved by the SDE. This must show all information concerning casing strings and wellhead equipment and accurate depths of suspension plugs, etc. In particular, the wellhead type, connector type and type of corrosion cap installed must be detailed.

3.

WELL ABANDONMENT

3.1

The main requirements for abandonment are:

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1.

To leave the well in a safe downhole condition such that there is no possibility of the well flowing when the BOP or wellhead is removed.

2.

To leave the seabed around the wellhead clear of drilling related debris.

To cover requirement 3.1.1, the following general guidelines apply to the plug-back operation: a)

If the well has been tested the test intervals will be isolated by cement or bridge plugs or by a combination of both.

b)

A cement plug will normally be set across the shallowest test interval with a minimum acceptable TOC 30m above the top of the interval. The plug will normally be tagged and weight tested.

c)

Where there is an open hole section a cement plug will normally be placed across the casing shoe, 50m below to 50m above. This is normally tagged. In many cases where the well reaches TD in 8 1/2” hole and the section is reasonably short (say up to 300m), it is common practise to cement back continuously from TD to 50m inside the shoe.

d)

Formations of different geological age in the open hole section are normally isolated by cement plugs.

e)

A bridge plug is normally set in the production casing at the depth of the intermediate casing shoe and a 100m cement plug set above this. If the open hole cement plug is extended to cover the shoe, then a bridge plug is to be set below production casing cut point.

f)

Where a potentially productive formation exists behind casing and is not cemented off, it will be necessary to isolate the interval (by squeezing or circulating cement behind the casing) prior to cutting the casing string. (If the formation is known to be at normal gradient and has no hydrocarbon content then this will generally not be required.)

g)

-

Alternatively, the casing string may be cut deep and a cement plug set across the cut.

-

If there is the possibility of pressure build-up in the annulus behind a casing string, then it may be necessary to perforate the casing below the wellhead while maintaining full BOP control prior to starting casing cutting operations. Any investigative work behind uncemented casing must be done with the BOP stack on.

When cutting casing the shoe strength at the previous casing shoe must be high enough to withstand the mud in the hole. If it is not, then the mud weight will have to be reduced. However, the mud weight left in the hole should be sufficient to afford a minimum 200 psi over-balance over formation pressure with the riser removed. Where these two factors conflict, the cutting depth will have to be shallow enough to allow the mud weight to be reduced.

Note: Refer to Table 1 for a summary of the minimum cement plug requirements. 3.3

It is a legislative requirement that all strings are cut a minimum 3m below seabed (CSON 12). Casings are normally cut fairly shallow with the proviso that the production string is cut deep enough to allow a cement plug to be placed across the cut (usually about 100m). The same applies to the 13 3/8” casing if it has not been cemented back inside the 20”, or if there are hydrocarbon bearing zones in the 13 3/8” - 20” annulus. There are two basic methods available to cut casing, i.e. mechanical or explosive cutting (refer also to Section 1850/SEM for details on Wellhead Severance). The choice of method will largely depend on water depth and past experience. The following points must be considered:

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a)

If water depth is less than ± 100m, then the rig may have to move off station if explosive cutting is used.

b)

In deep water (say greater than 300m), mechanical cutting is probably best avoided due to the need to rotate a long unsupported drill string. (The intermediate and production strings can of course be mechanically cut prior to pulling the riser.)

c)

At intermediate depths either method is applicable although modern mechanical cutting methods have a high probability of success and will usually be the preferred option. If the first attempt to cut the 20/30” casing fails, provided all indications show that the mechanical cutters have been fully extended, then further attempts should be made to cut the casings explosively.

Mechanical Cutting (Refer to Section 1850 : WELLHEAD SEVERANCE.)

3.5

Explosive Cutting (Refer to Section 1850 : WELLHEAD SEVERANCE.)

3.6

When abandoning a well an attempt is always made to recover the TGB, if installed. In some cases this has been found to be impossible due to the TGB being buried below the mudline and in this case it is sufficient to cut the guidewires at the seabed.

3.7

After retrieving the PGB, a ROV survey (or equivalent) must be carried out to confirm that the seabed is clear of drilling related debris to within a 70m radius of the wellhead. If debris is present then BP is obliged to recover it, and the recovery operation should be agreed with the Drilling Superintendent. A Seabed Clearance Certificate must be issued by the ROV (or Diving) Supervisor stating that the seabed is clear (or alternatively that there is debris which has not been recovered). This should be signed by the Diving (ROV) Superintendent and countersigned by the BP Drilling Supervisor who should ensure that this certificate, together with a well abandonment drawing, is sent to the rig’s DE Ops.

If condition of open hole precludes running pipe into it, set a bridge plug 30m above shoe with 50m cement above bridge plug.

3.

Top of liner.

50 - 75m above

50 - 75m below

4.

Stage cementer/casing patch.

50 - 75m above

50 - 75m below

5.

Perforations.

min. 30m above

30m below

If the well is abandoned, normally a 15m cement plug will be squeezed into any perforations. In some cases, if good isolation is achieved above and below the perforations, it may not be necessary to cement off the perforations. If the well is suspended then the productive interval should not be squeezed. In exceptional circumstances where formations have been fractured/stimulated then cement across the perforations may be replaced by a bridge plug above with 50m of cement above the bridge plug.

6.

Annular space (there should be no communication between seabed and open hole).

-

-

Cut casing 150 - 200m below seabed and revert to item 7.

7.

Top of cut casings.

50m above

50m below

8.

Surface plug (100m plug).

100m below seabed

9.

Bridge plug.

If the casing is cut shallow and plugged as in item 7, the requirement for a surface plug will have been satisfied. There should be a minimum of one bridge plug between the top of the liner (or perforations if no liner) and surface. Preferably, set the bridge plug just above the liner lap cement plug, or alternatively 250 - 500m below seabed.

1800/GEN

50 - 75m below

:

50 - 75m above

Section

Casing shoe (open hole below).

1 (12/90)

2.

:

For long permeable/interbedded sections not containing hydrocarbons, this requirement may be relaxed. If the hydrocarbon bearing zones have been tested, the zones must be separated by a bridge plug.

Rev.

30m below

5 of 6

min. 30m above

:

All porous/permeable zones and hydrocarbon zones isolated.

Page

1.

BP EXPLORATION

Alternative Option

DRILLING MANUAL

Bottom of Cement


Top of Cement

Plug Setting Points

SUBJECT:

TABLE 1 - CEMENT PLUG/BRIDGE PLUG REQUIREMENTS FOR THE ABANDONMENT AND SUSPENSION OF WELLS

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SUSPENSION AND ABANDONMENT PROCEDURES FIGURE 1

1100

1000

900

800

MINIMUM LATERAL OFFSET (FT)

700

600

500

400

300

200 10

15

20 25 30

40

50

75

100

100

0 200

300

400

500

600

700

800

900

1000

WATER DEPTH (FT) LATERAL OFFSET VS WATER DEPTH FOR VARYING CHARGE SIZE (LB NITRO METHANE) SEDCO 700 SERIES; 80 FT DRAFT; CHARGE 10 FT BELOW MUDLINE 2179 /155

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WELLHEAD SEVERANCE

1.

GENERAL

1.1

The following procedures apply to wellhead severance from semi-submersible rigs (refer also to Figure 1): 1.

The smaller diameter strings, i.e. 9 5/8” and possibly 7” should it be run to surface, should first be recovered by mechanical cutting and the BOP’s pulled.

2.

In cases where unsuccessful attempts have been made to abandon a well, the following considerations should be borne in mind when deciding the future course of action: a)

The Department of Energy “expects” companies to make a reasonable attempt at wellhead recovery at the time of well abandonment. Under normal circumstances, the 2 or 3 attempts recommended in the flowchart (Figure 1) can be considered reasonable.

b)

Prevailing weather conditions could severely influence matters. If bad weather is expected to delay anchor handling, then further attempts would be justified. However, if anchor handling could be completed before the onset of bad weather, then further severance attempts should stop. (Indeed in certain circumstances, this option may be considered prior to any severance attempts if a long period of WOW can be avoided.)

c)

The likely condition of the wellhead to be recovered and its suitability for refurbishment should be borne in mind, along with the existing wellhead stocking levels and any possible shortages.

Note: At present wellheads are re-used for a total of 2 - 3 wells before being scrapped. d)

The economic implications of using the rig as opposed to a diving vessel. The use of a diving vessel to recover the wellhead at a fixed cost reduces the risk exposure when wellhead removal proves to be troublesome.

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WELLHEAD SEVERANCE FIGURE 1 WELLHEAD RECOVERY FLOW CHART RECOVER SMALL DIAMETER STRINGS USING MECHANICAL CUTTER & PULL BOPS NOTE (i)

FIRE EXPLOSIVE CHARGE 10' (3M) BELOW SEABED

WELLHEAD RECOVERED?

YES

YES

CAN EXPLOSIVES BE USED WITHOUT MOVING RIG? NOTE (ii)

COMPLETE ABANDONMENT

NO

YES

MAKE MECHANICAL CUT AT 10' (3M) BELOW SEABED

WELLHEAD RECOVERED? NOTE (iii)

NO

NO

DO KNIVES INDICATE FULL CUT OF 30" CONDUCTOR ? NOTE (ii)

FIRE 2ND EXPLOSIVE CHARGE 10' (3M) BELOW SEABED

YES

NO

WELLHEAD RECOVERED?

YES

WAS A 30" TOP UP JOB PERFORMED ? NOTE (iii)

NO

YES

NO MAKE 2ND MECHANICAL CUT AT 10' (3M) BELOW SEABED

WELLHEAD RECOVERED? NOTE (iii)

NO

MOVE RIG OFF LOCATION AND FIRE EXPLOSIVE CHARGE 10' (3M) BELOW SEABED

YES YES

WELLHEAD RECOVERED?

NO

CONSIDER ALL OTHER FACTORS DEn, WEATHER, WELLHEAD STOCKS, RIG RATE, DIVING VESSEL RECOVERY ETC. NOTE (iv)

2179 /181

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WELLHEAD SEVERANCE

2.

“ONE TRIP” ABANDONMENT TOOLS

2.1

Introduction Mechanical cutting is BP’s primary method of wellhead severance. Explosives will be the primary method in water depths exceeding 800 ft or if economics dictate that the use of explosives will result in reduced abandonment costs. Care should be exercised in all aspects of the operation. The recovered, undamaged wellhead can be re-used resulting in substantial savings. The overriding consideration, when cutting and grappling the assembly for recovery, is to minimise external or internal damage of the wellhead joint, such that it can be re-used with minimal refurbishment costs. If damage to the wellhead is severe, its pressure rating may have to be downgraded following repairs, or in the worse case scrapped. Care and time should be taken when cutting. An unsuccessful cut can jeopardise abandonment operations, leading to increased costs and wastage of rig time. The system used to carry out the cutting and recovery operation should be carefully studied. The object is to successfully cut and recover the 20” and 30” in one operation. In an effort to reduce wellhead damage, abandonment tools and techniques have been developed to reduce contact between the wellhead, the wellhead internal profiles and the cutting and pulling assembly. Cutting in tension is the preferred option. With the DC’s and drill pipe in tension whilst cutting, there is no pipe buckling effect and current effects are virtually eliminated. A successful cut is readily noticed as a reduction in overpull at surface.

2.2

Stabilisation When the casing cutter is well stabilised above and below the cutting knives, cutting will be faster with a decreased chance of off-centre cutting. Drift sized stabilisers should be placed above and below the cutter. If casing design includes a reduced swaged diameter below the wellhead, a stabiliser should be included in the reduced diameter. Note the minimum diameter of the wellhead when gauging stabilisers for the cutting assembly. Stabiliser blades should be of the non-rotating type tapered top and bottom. Blades can have a thin “skin” of brass or similar material brazed onto their leading edges. This acts as a sacrificial layer when the stabiliser is passed through the sealing bore areas of the wellhead reducing contact damage.

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WELLHEAD SEVERANCE

PROBLEMS ASSOCIATED WITH CUTTING AND RETRIEVING

Note: If any special 20”/30” centralisers were run, the cut must be at least 5’ above or below the centraliser. 1.

If after cutting the casings, no progress is made in pulling the casings and guide bases, unlatch the retrieval mechanism and pull the cutting assembly. Carefully inspect the knives to check that they have been cutting at their maximum diameter. If the knives show e.g. only the 20” has been cut, re-run the assembly with new knives and cut the 30”. If both casings have been cut satisfactorily but the wellhead cannot be pulled free, consider running a fishing assembly to jar the wellhead and casings free. Economics may dictate that running an explosive charge rather than a fishing assembly to jar free the casings and guide bases may be more cost effective.

2.

The idea associated with cutting casings in tension is well established. As long as the equipment is working satisfactorily, cutting should be continued for a minimum of 6 hours, until the casings and wellhead can be pulled free. For simultaneous cutting of the 20” and 30”, if surface indications are such that both casings are cut, rotation should be stopped and the string overpulled in an attempt to pull the wellhead and both strings free. Circulation should be continued whilst pulling to assist in washing away formation or cement from the 30” and guide bases. If it is recognised at any time during the cutting operation that the knives are either worn or have broken, the spear should be released and the assembly pulled for inspection.

3.

Poorly cemented or uncentralised 20” when cut will have a tendency to move when cutting the 30”. If this occurs, off-centre cutting may occur, resulting in the 30” being partially cut on one side only. If after repeated pulling and cutting no progress is made, unlatch the spear and pull the cutting assembly for inspection.

4.

After examination of the knives, indications will be evident as to how large a diameter the knives have been cutting. If both strings have not been cut, redress the cutter with new knives and run the assembly back into the hole. If both casings have been cut, a cement sheath around the conductor may be preventing the casing coming free. An explosive charge should be run to fracture the cement sheath. A spear is then run to retrieve the casings and guide bases.

5.

Economic considerations may overrule a second run with a cutting assembly to complete the cutting of the 30” conductor. In that case an explosive charge is used to sever the conductor and to ensure that any cement sheath is fractured.

6.

Cutters can be fitted with a flotel device. This device can be adjusted to show a pressure decrease when the knives have reached their maximum cutting diameter. Usually if the casings are completely cut, and depending whether cutting was done in tension or under compression, the pipe will fall on top of the knives. A pressure drop will be noticed if the 30” is well cemented as the knives shear into the cement sheath. It is optional whether the flo-tel device is used. The decision to stop cutting should not be made on the basis of a pressure drop alone.

7.

If it is decided to release the spear or grappling mechanism from the wellhead on the seabed, problems can occur when attempting to release the grappling tool. If the knives are jammed in the cut pipe it may be difficult to release the spear from the wellhead, when using tension cut assemblies. To overcome this possibility a bumper sub can be placed in the assembly between the pipe cutter and the spear. This allows the spear to travel downwards the length of the stroke of the bumper sub. However a bumper sub placed in this position introduces a weak point in the assembly. Each situation should be given careful thought. Do not run a bumper sub in this position without consultation with the rig’s superintendent.

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WELLHEAD SEVERANCE FIGURE 2 SCHEMATIC OF A "ONE PASS" CUT AND RETRIEVE SYSTEM

,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,

,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, 30" CONDUCTOR ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, 20" CASING ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, 17 1/2" STAB ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,, ,,,,,,,,,,,,

,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,

,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,, 20" / 13 / " SWAGE ,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,, 13 / " CASING ,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,

,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,,,

,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,

,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, PIPE CUTTER ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,, ,,,,,,,,,,,,

38

38

,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,, 12 1/4" STAB ,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,

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WELLHEAD SEVERANCE

RED BARON AND SERVCO SYSTEM The Red Baron and Servco offer a one pass 20”/30” pipe cutting and wellhead retrieval system. Both operate in a similar fashion.

4.1

System Description The catch assembly is run in through the wellhead. On 18 3/4” wellhead equipment, the grapple locates under a profile immediately below the sealing areas contained within the wellhead. An overpull is taken on the wellhead of 10 - 25,000 lbs and the 20” and 30” pipe cut. Rotation of the string whilst the grapple is in tension is via a heavy duty bronze thrust bearing housed within the spear assembly. Minimum damage is done to the wellhead by the grappling mechanism resulting in minimum refurbishment costs, enabling the wellhead to be re-used if required. With the 20” and 30” satisfactorily cut, the wellhead and guide base are recovered simultaneously.

4.2

4.3

Equipment Preparation 1.

The casing cutter and spear should arrive on the rig site already made up. This saves rig time. All connections should be checked as the rest of the assembly is made up. Paint the lower 15’ of the assembly in advance. This will aid in ROV identification when stabbing into the wellhead.

2.

Gauge all stabilisers ensuring they will pass through minimum wellhead ID.

3.

Check spear is dressed with correct grapple to locate under profile in wellhead.

4.

Inform ROV team of operations well in advance.

5.

If logistically possible, organise a supply boat to receive recovered wellhead and guide bases to avoid deck space problems.

Operating Procedure For cutting and retrieving 20” and 30” in one pass, make up the following assembly: 8” bullnose, 17 1/2” NR stab, 11 3/4” pipe-cutter, 17 1/2” NR stab, rotating spear, 6 x 8” DC, HWDP to surface. If the wellhead consists of 20” casing swaged down to 13 3/8” casing, make up the following assembly: 8” bullnose, 12 1/4” NR stab, 1 x 8” DC, 11 3/4” pipe-cutter, 17 1/2” NR stab, rotating spear, 6 x 8” DC, HWDP to surface. All connections below the cutter should be made up to the maximum recommended torque of 43,500 ft.lbs. 1.

Set the knives for maximum cut of 38”. Push the knives fully back into the mandrel recesses. To ensure the knives do not come out of the recess and cause problems when going through the wellhead, wedge each knife in place using a piece of soft-line.

2.

Run the assembly into the moon-pool area and centralise the string with 4 soft lines attached to the guide wires.

3.

Carefully note the distance of the spear stop ring locating profile inside the wellhead from the extreme top of the wellhead. With the spear in the fully engaged position, paint a reference point mark on the assembly above the spear stop ring corresponding to this measurement. This mark can then be used to confirm the stop ring has located in the proper position when the assembly has been landed off inside the wellhead.

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4.

Run the assembly to 50’ above the guide posts. Do not rotate the string in open water.

5.

Jump the ROV.

6.

With ROV guidance, stab the bullnose into the wellhead.

7.

Carefully run the assembly through the wellhead and land the spear stop collar off with minimum weight. Use the ROV to check the position of the paint mark relative to the wellhead. This will confirm if the stop collar is in the correct position within the wellhead. Pull back and engage the spear in the wellhead pulling profile. Overpull 50,000 lbs to ensure grapple securely engaged and holding properly.

8.

Slack off overpull to working tension of 20-25,000 lbs.

9.

Set guide line tensions to slightly less than the combined weight of the cut casings and the guide bases.

10. Retrieve the ROV back to surface. 11. Rotate string bringing RPM up to 100. 12. Bring pumps slowly up to 400 GPM noting increase in torque as knives are pushed outwards into casing. The knives will begin cutting immediately. Note torque pattern which will tend to fluctuate around an average value. This indicates that the pipe is being cut rather than torn. If large torque variations are seen, rpm and circulation rate should be fine-tuned until the pattern smooths out. Once a regular cutting torque pattern has been established, set the rotary table or top-drive torque limiter to slightly above this value. In the event of the cut casings dropping onto the knives, the rotary or top-drive will stall out. This will prevent twist-offs and/or damage to the knives. 13. If a flotel is fitted, when the knives are fully extended, a pressure drop will be evident, indicating the 20” and 30” have been successfully cut. If the 30” is poorly cemented the cut pipe may drop onto the knives. The rotary or top drive should be immediately stopped. Stop circulation. 14. At the end of cutting operations, switch the pumps off to drop the knives back into their recesses. 15. Stop the rotary table or top-drive. If weather conditions permit, lock the compensator. Work the pipe to the maximum recommended for the string using the heave of the vessel for assistance to free the casings and guide bases. Do not shock load the assembly as this will only result in damage to the spear and/or bearing possibly leading to a fish in the open water. 16. Jump the ROV. Cut and retrieve the guide wires. Retrieve the ROV to surface. 17. Pull the wellhead and cut pipe to surface. 18. With the wellhead and guide base secured on the moonpool beams, slack off weight on the rotating spear. Turn the string 1/8 turn to the right. This will close the clutch on the spear allowing the assembly to be pulled free from the wellhead.

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WELLHEAD SEVERANCE

TRI-STATE SYSTEM Tri-State offers a one pass 20”/30” pipe cutting and wellhead retrieval system.

5.1

System Description The cutting assembly is run into the wellhead and the spear is landed off with the stop ring on top of the wellhead. The spear is locked into the internal running threads of the wellhead with 4 mechanically activated dogs. An overpull is taken on the wellhead and the pipe is cut in tension. Rotation of the string whilst the spear dogs are locked into the wellhead is via a heavy duty bronze thrust bearing housed within the spear assembly. Minimum damage is done to the wellhead by the grappling mechanism resulting in minimum refurbishment costs enabling the wellhead to be re-used if required. With the 20” and 30” satisfactorily cut, both the wellhead and guide base are recovered simultaneously.

5.2

5.3


The casing cutter and rotating spear assembly should arrive on the rig site already made up. This saves rig time. All connections should be checked as the rest of the assembly is made up. Paint the lower 15’ of the assembly in advance. This will aid in ROV identification when stabbing into the wellhead.

2.

Gauge all stabilisers, ensuring they will pass through minimum wellhead ID.

3.


4.


Operating Procedure For cutting and retrieving 20” and 30” in one pass, make up the following assembly: 8” bullnose, 17 1/2” NR stab, 11 3/4” pipe-cutter, 17 1/2” NR stab, rotating spear assembly, bumpersub, 6 x 8” DC, HWDP to surface. For cutting swaged 20”/13 3/8”, make up the following assembly: 8” bullnose, 12 1/4” NR stab, 11 3/4” pipe-cutter, 17 1/2” NR stab, rotating spear assembly, bumpersub, 6 x 8” DC, HWDP to surface. All connections below the cutter should be made up to the maximum recommended torque of 43,500 ft.lbs. 1.

Set the knives for maximum cut of 42”. Push the knives fully back into the mandrel recesses. To ensure the knives do not come out of the recess and cause problems when going through the wellhead, wedge the knife in place using a piece of soft-line. Ensure the locking dogs are fully back, flush with the body of the spear. The spear mandrel is turned fully anti-clockwise to locate the key away from the keyway slot.

2.


3.


4.

Jump the ROV.

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5.


6.

Carefully land off the assembly on the spear stop ring on top of the wellhead with 10,000 lbs. Confirm with the ROV that the bumper sub is fully closed and the stop ring has fully landed off on top of the wellhead.

7.

With the string fully landed off and the bumper sub closed, put 10,000 lbs on top of the stop ring.

8.

Turn string 1/4 to 1/2 turn to the right. This aligns the mandrel key and keyway slot. Pick string up. On lifting the string a taper on the mandrel forces out the locking dogs into the wellhead running tool threads.

9.


10. Retrieve the ROV back to surface. 11. Pull 20-25,000 lbs tension on the string. Rotate string bringing RPM up to 100. 12. Bring pumps slowly up to 400 GPM noting increase in torque as knives are pushed outwards into casing. The knives will begin cutting immediately. Note torque pattern which will tend to fluctuate around an average value. This indicates that the pipe is being cut rather than torn. If large torque variations are seen, rpm and circulation rate should be fine-tuned until the pattern smooths out. Once a regular cutting torque pattern has been established, set the rotary table or top-drive torque limiter to slightly above this value. In the event of the cut casings dropping onto the knives the rotary or top-drive will stall out. This will prevent twist-offs and/or damage to the knives. 13. If a flotel is fitted, when the knives are fully extended, a pressure drop will be evident, indicating the 20” and 30” have been successfully cut. If the 30” is poorly cemented the cut pipe may drop onto the knives. The rotary or top drive should be immediately stopped. Stop circulation. 14. At the end of cutting operations, switch the pumps off to drop the knives back into their recesses. 15. Stop the rotary table or top-drive. 16. If weather conditions permit, lock the compensator. Work the pipe to the maximum recommended for the string using the heave of the vessel for assistance to free the casings and guide bases. Do not shock load the assembly as this will only result in damage to the spear and catching mechanism, possibly leading to a fish in the open water. 17. Jump the ROV. Cut and retrieve the guide wires. Retrieve the ROV to surface. 18. Pull the wellhead and cut pipe to surface. 19. With the wellhead and guide base secured on the moonpool beams, slack off to neutral weight and turn the string 1/4 to 1/2 turn to the left. Lower the string 10 inches to allow the locking dogs to disengage from the wellhead running tool threads. 20. Pull assembly from the wellhead.

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WELLHEAD SEVERANCE

A-1 M.O.S.T. SYSTEM A-1 M.O.S.T. (mechanically outside single trip) offers a one pass 20”/30” pipe cutting and wellhead retrieval system.

6.1

System Description The cutting and retrieving assembly is run in through the wellhead. The M.O.S.T. retrieval tool is located on top of the wellhead and landed off. Pipe rotation, whilst the M.O.S.T. tool is landed off, is via a marine swivel placed above the tool. The 20” and 30” are cut in compression with weight on the swivel. Once the pipe is cut, the mechanically activated arms are latched onto the outside wellhead profile. The cut pipe and guide bases are then pulled to surface with the cutting assembly. Minimum wellhead damage is incurred in the cutting and grappling procedure. The refurbished wellhead can be re-used if required.

6.2

6.3


The casing cutter and M.O.S.T. tool should arrive on the rig site already made up. This saves rig time. All connections should be checked as the rest of the assembly is made up. Paint the lower 15’ of the assembly in advance. This will aid in ROV identification when stabbing into the wellhead.

2.


3.


4.


Operating Procedure For cutting and retrieving 20” and 30” in one pass, make up the following assembly: 8” bullnose, 17 1/2” NR stab, 11 3/4” pipe-cutter, 17 1/2” NR stab, M.O.S.T. tool/marine swivel, 6 x 8” DC, HWDP to surface. For cutting swaged 20”/13 3/8”, make up the following assembly: 8” bullnose, 12 1/4” NR stab, 11 3/4” pipe-cutter, 17 1/2” NR stab, M.O.S.T. tool/marine swivel, 6 x 8” DC, HWDP to surface. The string above the swivel is composed of enough collars to have available 20,000 lbs downweight on the swivel and the rest of the HWDP kept in tension. This will minimise string buckling in the open water. The pipe cutter has 4 knives and as such will greatly aid stabilisation. All connections below the cutter should be made up to the maximum recommended torque of 43,500 ft.lbs. 1.

Set the knives for maximum cut of 42”. Push the knives fully back into the mandrel recesses. To ensure the knives don’t come out of the recess and cause problems when going through the wellhead, wedge the knife in place using a piece of soft-line.

2.


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3.


4.

Jump the ROV.

5.


6.

Carefully land off the M.O.S.T./marine swivel on top of the wellhead with 10,000 lbs.

7.


8.

Retrieve the ROV back to surface.

9.

With 10-15,000 lbs weight on the swivel, rotate string bringing RPM up to 100.

10. Bring pumps slowly up to 400 GPM noting increase in torque as knives are pushed outwards into casing. The knives will begin cutting immediately. Note torque pattern which will tend to fluctuate around an average value. This indicates that the pipe is being cut rather than torn. If large torque variations are seen, rpm and circulation rate should be fine-tuned until the pattern smooths out. If the wellhead turns during cutting operations, slack off more weight on the marine swivel. Once a regular cutting torque pattern has been established, set the rotary table or top-drive torque limiter to slightly above this value. In the event of the cut casings dropping onto the knives the rotary or top-drive will stall out. This will prevent twist-offs and/or damage to the knives. 11. If a flotel is fitted, when the knives are fully extended, a pressure drop will be evident, indicating the 20” and 30” have been successfully cut. If the 30” is poorly cemented, the cut pipe may drop onto the knives. The rotary or top drive should be immediately stopped. Stop circulation. 12. At the end of cutting operations, switch the pumps off to drop the knives back into their recesses. 13. Stop the rotary table or top-drive. 14. Pick up string 6 inches and rotate 1/2 turn to the left. This engages the arms on the outside wellhead profile. 15. Stop the rotary table or top-drive. If weather conditions permit, lock the compensator. Work the pipe to the maximum recommended for the string using the heave of the vessel for assistance to free the casings and guide bases. Do not shock load the assembly as this will only result in damage to the M.O.S.T. tool and/or marine swivel, possibly leading to a fish in the open water. 16. Jump the ROV. Cut and retrieve the guidelines. Retrieve the ROV back to surface. 17. Pull the wellhead and cut pipe to surface. 18. With the wellhead and guide base secured on the moonpool beams, slack off weight and locate the release mechanism for the mechanical arms on the M.O.S.T. tool. Turn string 1/2 turn to right. This releases the spring loaded arms. Pull assembly from wellhead.

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WELLHEAD SEVERANCE

DEEPWATER SYSTEM Deepwater offer a one pass 20”/30” pipe cutting and wellhead retrieval system.

7.1

System Description The cutting assembly is run in through the wellhead and landed off on top of the wellhead with 8-10,000 lbs weight. The 20” and 30” are cut in compression with weight on the swivel. Rotation of the string is via a marine type swivel which is housed within the upper part of the land-off and grappling assembly. To retrieve the cut casings and wellhead, 6 segmented dogs on the land-off/swivel unit are mechanically forced outwards into the internal running tool threads of the wellhead. With the 20” and 30” satisfactorily cut, the pipe and wellhead are retrieved together. Minimum wellhead damage is incurred in the cutting and grappling procedure. The refurbished wellhead can be re-used if required.

7.2

7.3


The casing cutter and land-off/marine swivel unit should arrive on the rig site already made up. This saves rig time. All connections should be checked as the rest of the assembly is made up. Paint the lower 15’ of the assembly in advance. This will aid in ROV identification when stabbing into the wellhead.

2.


3.


4.


Operating Procedure For cutting and retrieving 20” and 30” in one pass, make up the following assembly: 8” bullnose, 171/2” NR stab, 11 3/4” pipe-cutter, 17 1/2” NR stab, land-off/marine swivel unit, 6 x 8” DC, HWDP to surface. For cutting swaged 20”/13 3/8”, make up the following assembly: 8” bullnose, 12 1/4” NR stab, 11 3/4” pipe-cutter, 17 1/2” NR stab, land-off/marine swivel unit, 6 X 8” DC, HWDP to surface. The string above the swivel is composed of enough collars to have available 20,000 lbs downweight on the swivel and the rest of the HWDP kept in tension. This will minimise string buckling in the open water. All connections below the cutter should be made up to the maximum recommended torque of 43,500 ft.lbs. 1.

Set the knives for maximum cut of 42”. Push the knives fully back into the mandrel recesses. To ensure the knives don’t come out of the recess and cause problems when going through the wellhead, wedge the knife in place using a piece of soft-line. Paint 3 large vertical lines on the marine swivel unit and upper mandrel to correspond with the three dog locating keyways within the tool.

2.

Run the assembly with the spear in the fully locked disengaged position, i.e. the vertical paint lines should be at 60 degrees to each other, into the moon-pool area and centralise with 4 soft lines attached to the guide wires.

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WELLHEAD SEVERANCE

3.


4.

Jump the ROV.

5.


6.

Carefully land off the marine swivel/land-off unit on top of the wellhead with 10,000 lbs.

7.


8.

Retrieve the ROV back to surface.

9.

With 10,000 lbs weight on the swivel, rotate string bringing RPM up to 100.

10. Bring pumps slowly up to 400 GPM noting increase in torque as knives are pushed outwards into casing. The knives will begin cutting immediately. Note torque pattern which will tend to fluctuate around an average value. This indicates that the pipe is being cut rather than torn. If large torque variations are seen, rpm and circulation rate should be fine-tuned until the pattern smooths out. If the wellhead turns during cutting operations, slack off more weight on the marine swivel. Once a regular cutting torque pattern has been established, set the rotary table or top-drive torque limiter to slightly above this value. In the event of the cut casings dropping onto the knives the rotary or top-drive will stall out. This will prevent twist-offs and/or damage to the knives. 11. If a flotel is fitted, when the knives are fully extended, a pressure drop will be evident, indicating the 20” and 30” have been successfully cut. If the 30” is poorly cemented the cut pipe may drop onto the knives. The rotary or top drive should be immediately stopped. Stop circulation. 12. At the end of cutting operations, switch the pumps off to drop the knives back into their recesses. 13. Stop the rotary table or top-drive. 14. Rotate the string 1/3 of a turn to the right. Pick up the string 4-6 inches. The swivel unit mandrel is then allowed to move upwards and forces out 6 segmented dogs into the wellhead running tool thread profile. The 3 vertical paint marks on the swivel and mandrel should now be aligned. The wellhead is now locked in place and ready for pulling. 15. If weather conditions permit, lock the compensator. Work the pipe to the maximum recommended for the string using the heave of the vessel for assistance to free the casings and guide bases. Do not shock load the assembly as this will only result in damage to the grappling tool and swivel, possibly leading to a fish in the open water. 16. Jump the ROV. Cut and retrieve the guide wires. Retrieve the ROV back to surface. 17. Pull the wellhead and cut pipe back to surface. 18. With the wellhead and guide base secured on the moonpool beams, slack off weight and allow the swivel unit mandrel to be further lowered by 4-6 inches. Turn the string 1/3 to the right. In this position, with the paint marks at approx. 60 degrees to each other, when the string is picked up the mandrel is unable to travel upwards. The 6 locating dogs are then free to disengage and fall away from the wellhead running tool thread profile. 19. Remove the cutting and retrieval assembly from the wellhead.



Index Prefixes 0000


1000

Drilling

2000

Casing and Tubing

3000

Cementing

4000

Drilling Fluids

5000


6000


7000

Well Evaluation

8000






Section

Description

2000

CASING AND TUBING

2000/GEN

Prep. & Running Casing - General

2005/GEN

Casing Design

2010/GEN

Casing Centralisation

2100/SEM

Prep. & Running 30" Conductor/PGB - Dril-Quip SS15 System

2100/JAK

Prep. & Running 30" Conductor and Stab-In Cement Stinger Assy

2105/FIX

Cutting & Preparation of Casing to Accept Wellhead Spools

2200/SEM

Prep. & Run 20"/18.5/8" Casing - Dril-Quip SS15 System

2200/FIX

Prep. & Run 20"/18.5/8" Casing - General

2300/FIX

Prep. & Run 13.3/8" Casing

2300/SEM

Prep. & Run 13.3/8" Casing - Dril-Quip SS15 System

2400/FIX

Prep. & Run 9.5/8" Casing

2500/FIX

Prep. & Run 7" Casing

2510/GEN

Prep. & Run 7" Baker (Brown) HMC Liner Hanger

2515/GEN

Prep. & Run 7" Baker (Brown) HSR Rotating Liner Hanger

2520/GEN

Prep. & Run 7" Baker (Brown) HSR Liner Hanger with CPH Packer

2525/GEN

Prep. & Run 7" TIW Liner Hanger

2530/GEN

Prep. & Run 7" TIW Liner Hanger with Integral Packer


SUBJECT:


2535/GEN

Prep. & Run 7" Nodeco Rotating Liner Hanger with TSP Packer

2540/GEN

Prep. & Run 7" Lindsey-Arrow HSB-SC Liner Hanger with WM-P Packer

2545GEN

Prep. & Run 7" Enaco/TIW Rotating Liner Hanger with 'S' Packer and SJ-T mechanical Rotating Tool

2550/GEN

Prep. & Run 4.1/2" Nodeco Rotating Liner Hanger with TSP Packer

2560/GEN

Prep. & Run 5" Baker HMC Liner Hanger with CPH Packer

2600/GEN

External Casing Patch Operations

2700/GEN

Connectors: Hunting Merlin

2705/GEN

Connectors: Hunting Lynx

2715/GEN

Connectors: Vetco SR-20

2720/GEN

Connectors: Vetco ALT Series

2725/GEN

Connectors: Vetco RL-4S

2800/GEN

BP Standard Casing Data

2900/GEN

Tubing Preparation & Running Procedures

2950/GEN

Chrome Tubular Handling 13%

2960/GEN

Duplex 25% Chrome Tubular Handling/Running Procedure


SUBJECT:


2250/CLY

Prep. & Run 20" Clyde

2250/THI

Prep. & Run 20" Thistle

2250/AME

Prep. & Run 20" Contingency String - Amethyst

2260/FOR

Prep. & Run 18.5/8" Forties

2260/MAG

Prep. & Run 18.5/8" Magnus

2260/BRU

Prep. & Run 18.5/8" Bruce

2260/WYF

Prep. & Run 18.5/8" Casing Wytch Farm

2300/WYF


2350AME

Prep. & Run 13.3/8" Casing - Amethyst

2400/WYF


2450/AME

Prep. & Run 9.5/8" Casing - Amethyst

2550/WYF

Prep. & Run 5.1/2" Nodeco Rotating Liner Hanger with TSP Packer Wytch Farm


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PREPARATION & RUNNING OF CASING: GENERAL

1.

GENERAL ROUTINES AND PREPARATIONS FOR RUNNING CASING

1.1

It is the responsibility of the Drilling Supervisor to ensure that all equipment has been ordered and is on site prior to the casing job.

1.2

On exploration wells at each new location the initial load-out will usually consist of the drilling equipment for the 36” and 26” sections plus two sets of guide bases and wellheads, two strings of 30” conductor and one string of 20” casing. This load-out will usually be timed to arrive at the rig as the anchors are being run.

1.3

On exploration wells telex orders for subsequent casing strings should be sent when drilling commences on the new hole section.

1.4

Check that the casing weight/grade/connection is correct for the well programme and where a mixed string is being run that sufficient pipe of each type is available. When using subsea wellheads check that the casing hanger extension is the correct grade of pipe. Refer to page 7 for details of colour code marking for tubing and casing.

1.5

When casing is delivered and racked, remove protectors and thoroughly clean and check casing threads. For further information, refer to Section 2800/GEN - Tubular Preparation and Running Guide.

1.6

On completion of each layer, the BP Drilling Supervisor/Engineer and Contractor TP will independently measure the casing, after which the numbers are painted on. It is essential that there are two independent measurements which correlate. For each row the lowest numbered pipe should be farthest from the catwalk.

1.7

The BP casing tally sheet must be used to list the pipe as laid down. Only corrected lengths should be marked on the tally.

1.8

When measuring is completed the BP Drilling Supervisor should count the total amount of joints on board, and compare this with the pipe tally and consignment figures. He then should add up all columns on the pipe tally and check the totals with those of the Contractor TP.

1.9

Casing to be drifted with the correct sized API drift - any failures to be clearly marked. Ensure that the drift mandrel dimensions conform to API RP 5A5: 8 5/8” casing and smaller: 9 5/8” casing and larger: Tubing (all sizes):

mandrel length 6” mandrel length 12” mandrel length 42”

1.10

After the casing has been drifted the BP Drilling Engineer should then make up the casing running programme and have it checked by the BP Drilling Supervisor. As soon as the BP Drilling Supervisor has agreed with the programme, a running list is to be prepared stating exactly the joints to be run and to be left out. Joints to be excluded from the string should be clearly marked, and the running list should indicate clearly the joints where centralisers should be attached.

1.11

After the casing has been measured and drifted, dope the pin and box ends with API modified dope and replace the thread protectors (hand tight).

Note: This does not apply to 20” and 30” connectors. 1.12

Check placement of shoe and collar, or special casing equipment. Welding on casing is not permitted. The collars of the joints making up the “shoe track” should be removed and made up again with the proper torque and a thread locking compound should be used. Float collars, shoes and DV collars should be made up similarly. Collars that have been threadlocked in town will arrive with the collars painted yellow. Threadlocking of collars in the rotary table is to be avoided, and whenever possible should be carried out on deck beforehand.

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When threadlocking on the rig floor, make sure both pin and box are clean and dry, only place the locking compound on the pin of the connection with the joint pulled to one side, spatulas have been known to drop into the casing as well as dope brushes. Threadlock may not be used on some quick connector threads, e.g. Vetco LS. Single joint and side door elevators to be tried on several casing joints on deck to check “fit”. All accessories should be made up on casing pin ends to ease fishing operations should the casing drop through the slips into the hole.

1.14

Both shoe and collar joint should be fitted with a blanked off casing thread protector as soon as shoe/collar have been installed. This is to prevent foreign objects from entering joint during storage/handling.

1.15

Casing OD Tolerances The standard API tolerance on casing OD (all grades) is +1.0%, -0.5%. Casing centralisers are currently manufactured to fit the 1% tolerance. Some casing grades (e.g. HC95 and HC110) have additional tolerances: For 13 3/8” 72 lb/ft HC95 and HC110 with 12 1/4” drift there is an additional 0.080” above API, making maximum OD = 13.589”. These casings require special elevators and accessories. For 9 5/8” 43.5 lb/ft and 47 lb/ft HC95 and HC110 there is no additional tolerance, making maximum OD = 9.721”. For 9 5/8” 53.5 lb/ft HC95 and HC110 with 8 1/2” drift there is an additional 0.075” above API, making maximum OD = 9.796”. Note that for 9 5/8” 53.5 lb/ft with 8 1/2” special drift in other grades there is an additional 0.025” above API, making maximum OD = 9.746”. This variance in tolerance depends upon manufacturer and advice should be obtained from DTD, Dyce.

1.16

Determine the amount of cement required; from the caliper or experience, and the drilling programme.

1.17

Order cement and additives well in advance, and notify cementers in time to have the cement equipment rigged up and tested prior to landing the casing. Take samples of newly arrived cement and send in to town along with samples from the liquid additives, drill water and seawater for slurry testing.

1.18

See that sufficient water and displacing fluid is available and that adequate supply lines are provided for the cementers.

1.19

Have Mud Engineer check mud is in good condition prior to pulling out of hole for casing (low viscosity YP and PV/YP ratio). Where tank capacity allows, ensure that displacement fluid is pumped from and received into separate tanks. This provides a positive method of measuring losses and displacement volumes.

1.20

Mud pumps should be fitted with the proper size liners and be in good mechanical condition. Ensure that the mud pump relief valve is correctly set and tested. Have a low pressure mud fill up line rigged up with a quick opening valve for high rate casing fill.

1.21

The hole depth must be checked by measuring out of the hole at least once prior to reaching a critical depth such as casing point, logging point, etc. and if these measurements do not agree the pipe should be remeasured.

1.22

It is the responsibility of the Drilling Supervisor to check that all running tools and equipment are in good condition and are the correct rating for the job and covered by valid certification. In particular:

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a)

Side door elevators should be checked for uneven wear on the bearing surface and for correct operation of the door latch. Elevators should be checked by trial latching before the casing is run. Grinding of elevators is dangerous and should be avoided.

b)

Spider and elevator slips and guides should be checked for size, condition and the ability to operate evenly.

c)

Load capabilities of the block line.

Stabbing board to be checked out as per the safety check list, duly signed by the person making the inspection, Senior Toolpusher and Drilling Supervisor. This must be carried out prior to any use of the stabbing board.

1.24

On returning casing to supply base all joints should be protected, therefore, keep behind sufficient pin and box protectors for the estimated return load. A Casing Return Telex should be sent notifying backload. Any damaged joints should be clearly marked with red paint and manifested separately. Any joints failing the drift check should be clearly marked “NO DRIFT” in red paint and manifested separately.

1.25

If a “slip-type” Casing Hanger is to be used, check 3 casing joints for ovality and set aside for use across the wellhead spool.

1.26

Ensure all power tongs and conventional tongs are checked out before the job.

1.27

If Wellhead Casing cutting is to be used, check and prepare the casing cutter on the wellhead deck (see Section 2105/FIX).

1.28

Well Control Rigfloor

:

Ensure that a full opening valve (Lower Kelly Cock or similar) made up to a casing crossover is held on the rigfloor.

BOP’s

:

On surface stacks, ensure that the upper pipe rams are dressed with the correctly sized casing rams and the bonnet seals pressure tested to the stack test pressure, unless a specific dispensation is issued by the Drilling Superintendent.

1.29

Check all Wellhead Equipment to be used on the Casing Installation is as per Wellhead Sections.

1.30

Check compatibility/suitability of all cementing accessories, shoe float, stage cementer equipment, cementing stingers, etc.

1.31

If using any type of quick connector, either threaded or snap lock system, clean pin and box ends thoroughly, inspect threads and seal faces/shoulders, inspect and replace any damaged elastomers, lubricate with a light oil. DO NOT USE THREAD DOPE, METALLIC GREASE COMPOUNDS OR ANY LOCKING COMPOUNDS ON THESE TYPES OF CONNECTOR.

2.

CASING RUNNING OPERATIONS

2.1

Visually check the inside of each joint of casing on the rack to see that all joints are clear of foreign materials. Both shoe joint and collar joint should be fitted with a blanked off casing thread protector as soon as shoe/collar have been installed. This is to prevent foreign objects from entering joint during storage/ handling.

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2.2

On liner jobs and 20” casing cementations drift all drillpipe used with the proper size “rabbit”. Ensure that all plugs used in SSR and liner operations are the correct size for the drillpipe.

2.3

Place short joint(s) in the casing string near the pay zone(s) to aid later in checking depths with a casing collar locator (CCL), if required. On exploration wells two pup joints are generally required, one within the reservoir and one +/- 50m above the top of the reservoir.

2.4

Check conventional casing float equipment and surface mud lines after the shoetrack is run in.

2.5

Fill up casing every joint and completely every 5 joints via a low pressure mud line rigged up with a quick opening valve.

2.6

Ensure the casing is made up to the correct torque, in the case of buttress couplings the following procedure is to be adopted: The routine to obtain the average power tight make-up torque is to bring the face of the collar to the base of the triangle on each of the first 10 joints after the pipe locked shoetrack and establish the average make-up torque for these. This average is applied to make-up the remaining joints using spot checks on the position of the face of the collar relative to the triangle base. Provided the position falls within -0.2” and +0.375” of the base, the power tight make-up is acceptable. Refer to sketch shown below.

Range of collar position on subsequent joints at average make-up torque.

0.375 in. Collar position for 1st 10 joints 0.2 in.

CASING COLLAR FACE VAM Couplings: Note that the make-up torque on VAM connections has been changed as of October 1988 to account for the introduction of “NEW VAM”. All VAM couplings will be made up to the new ratings. “NEW VAM” can be made up into “OLD VAM” as long as the make-up torque for “NEW VAM” is used. For further information on VAM connections, refer to Section 2711/GEN “Casing Connection Data NEW VAM”. 2.7

Refer to Section 2800/GEN for data on tubulars used in BP’s operations.

2.8

Regulate casing lowering speed to 30 sec/jt (0.4 m/sec) or to the optimum speed as indicated by pressure surge/swab calculations. Caution driller of possible lost circulation if casing is run too fast and check for full returns every joint.

2.9

When the side door elevator is in use, avoid impact loading, which can open this type of elevator. Particular care must be taken when centralisers are entering rotary or BOP/wellhead. When the hook load becomes large and always when leaving casing shoe, use slip type elevators (not for 20” casing).

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2.10

Wherever possible or practical, wash down the last 1 - 2 joints of casing.

2.11

Break circulation slowly. Record free hanging weight of the string. Circulate at least casing contents + 20% (or annular content, whichever is greater). Record circulating pressures and rates up to a maximum rate allowable from pressure considerations, i.e. 85% of formation breakdown, casing test pressure, losses, etc. Pump and displace cement at rates as indicated by the drilling programme. (High displacement rates prior to landing the bottom plug could cause plug collapse at landing due to mud column inertia.)

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SUBJECT:


CASING DESIGN

Refer to BPX Casing Design Manual (PSR-X06).

Section

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Rev.

:

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CASING CENTRALISATION

GENERAL Casing centralisation is a critical parameter in ensuring the objectives of primary cementing can be achieved. The degree to which a casing has been centralised in open hole is referred to as stand-off. This is defined as: 100 x

(Width of narrowest part of annulus) (Diameter of hole - diameter of casing) / 2

The most common centralisers are bow spring and solid/positive/rigid centralisers. As hole angle increases the effective weight of the casing on the low side of the hole increases. The higher wall forces generated require additional centralisers to prevent casing resting on the low side of the hole. The recommendations in this section should be used to determine a centralisation programme required for wells for hole angles up to 50 deg. When the hole angle exceeds this or centralisation is required in a build section, the casing wall forces should be calculated using the Drill String Simulator and the suppliers of the centralisers contacted to determine the type of centraliser required and the optimum positions. Should a separate programme be run to determine centraliser placement, ensure that the actual restoring force of the centraliser is used and not the API value. Centralisers usually exceed the restoring force of the API specification. Rigid centralisers only have application where the hole is not more than 1/4" larger than the OD of the centraliser or where the wall forces preclude the use of a bow spring centraliser. Hence the most common applications will be inside casing and across build sections. 2.

RECOMMENDED CENTRALISERS AND INSTALLATION The Weatherford range of centralisers are currently on a Purchase Agreement. Table 1 details the centralisers which should be used and the options on installation. The OD of a positive centraliser, if used, should be at least 1/8" smaller than the minimum OD of the casing in which it is run. The recommended installation procedures are:

2.1

Spring Bows

Type

Position

STVIII STIV STIII

Over casing coupling. Over casing coupling. Over stop collar (if placed between coupling and stop, separation must be greater than the compressed length of the centraliser). Between stop collar and coupling (see note above).

STI 2.2

Positives

Type

Position

PO I-PO X

Between stop collar and casing coupling.

13 3/8"

9 5/8" 7"

PO X PO X PO VIII

26", 1" Wall

18 5/8" (87.5)

13 3/8" (72) 9 5/8" (53.5)

Csg. & Hole Sizes Centraliser Type

Starting Force (lbs)

Running Force (lbs)

Restoring Force (lbs)

20-26 STVIII

3700

1706

4000 +

20-24 STIV

4048

1176

2664

Rigid C,D

18 5/8" - 26" STVIII

1448

1018

4646

Spring A,B,C,D

18 5/8" - 24" STIV

872

548

3032

Installation

Rigid C,D

PO IX

JSH

Spring A,B,C,D

13 3/8" - 17 1/2" STIV 13 3/8" - 16" STIII

1149 1128

665 1189

1783 3513

951

513

1684

STIII

JSH

Rigid C,D Spring B,C,D

9 5/8" - 12 1/4" STIII

12 1/4" 8 1/2"

STI STIM

Rigid C,D Spring C,D

7 - 8 1/2" STI

698

506

2648

JSH

4 1/2" - 6" STIM

375

245

886

Rigid C,D

PO V PO I

STRAIGHT BOW WELDED STRAIGHT BOW/ROTATING LINERS

INSTALLATION KEY:

A B C D

-

OVER A CASING COUPLING OVER A STOP COLLAR BETWEEN STOP COLLAR AND CASING COUPLING BETWEEN TWO STOP COLLARS

2010/GEN

STIV STIII

PO VIII

:

17 1/2" 16"

J10H

Section

STVIII STIV STIII

Spring A,B,C,D Rigid C,D

5 (5/92)

26" 24" 23"

J10H

:

STVIII STIV

Rev.

26" 24"

2 of 9

= =

Stop Collar Type

:

STI STIM

Centraliser Spring Type

Page

NOTES:

30", 1.5" Wall 30", 1" Wall 26", 1" Wall

Open Hole Type

BP EXPLORATION

18 5/8"

Centraliser Rigid Type

DRILLING MANUAL

20"

Previous Casing Size

TABLE 2 Type of Centraliser and Running, Starting and Restoring Forces


Casing Size

SUBJECT:

TABLE 1 Centralisers and Installation Procedure

* RESTORING FORCE AT 67% STAND-OFF

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DETERMINING CENTRALISATION REQUIREMENTS

OVER WHAT INTERVALS IS GOOD ISOLATION ESSENTIAL?

IN THESE SECTIONS AIM FOR 80% STAND-OFF ASSUMING GAUGE HOLE. IF THIS ZONE IS TO BE CEMENTED ALONE, OPTIMISE PLACEMENT USING WEIGHTED SPACERS AND REDUCED MUD GELS.

ARE THERE ZONES WHERE CASING COULD GET STUCK IF STATIC FOR MORE TIME THAN MAKING A CONNECTION CENTRALISE AT THESE POINTS?

DO YOU HAVE TO PUMP CEMENT OVER ANY OTHER SECTION?

YES IS PROBLEM SOLVED BY PUMPING FASTER/SLOWER?

IF NO CENTRALISERS ARE USED, COULD CEMENT CHANNEL AND RETURN TO SURFACE OR FRAC A WEAK ZONE? NO

YES

NO IS PROBLEM SOLVED BY REDUCING CEMENT EXCESS?

YES

NO COMPARE THE COST OF THE FOLLOWING THREE OPTIONS: A B C

IMPROVE STAND-OFF WITH MORE CENTRALISERS, CONSIDER THE EFFECT ON RUNNING CASING. MODIFY THE DENSITY OF SPACER AND/OR CEMENT. TREAT MUD GELS CONSIDERING TIME TAKEN AND CHEMICALS REQUIRED.

CHOOSE STAND-OFF DISPLACEMENT RATE AND FLUID PROPERTIES.

DO NOT CENTRALISE.

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4.

CENTRALISATION PROGRAMMES

4.1

20" and 18 5/8" Casing

4.1.1

Vertical Wells Two spring centralisers on shoe joint, one 2m above the shoe and the other around or below the collar. Spring centralisers on second and fourth joint and first 2 joints inside the 30" casing. Rigid centraliser above and below seabed on jack-ups and platforms. Rigid centraliser on first 2 joints below the wellhead on jack-ups and platforms.

4.1.2

Deviated Wells Two spring centralisers on shoe joint, one 2m above the shoe and the other around or below the collar. One spring centraliser every second joint for hole angles between 5 - 30 deg. At larger hole angles a separate analysis should be performed. Spring centralisers on first 2 joints inside the 30" casing. Rigid centraliser above and below seabed on jack-ups and platforms. Rigid centraliser on first 2 joints below the wellhead on jack-ups and platforms.

4.2

13 3/8" Casing To determine centralisers required in open hole section, use Figure 1. In the event that there is no knowledge of actual hole size, programme greater than 80% stand-off where isolation is critical. If calliper data is available, programme to achieve greater than 70% after allowing for hole OD using Figure 1. If centralisation is required in any section where the wall forces exceed 4,000 lbs per joint, rigid centralisers must be used if centralisation is required. •

NO MLS EQUIPMENT BEING USED Centralisers on first two joints inside 20" shoe. Rigid centraliser on first two joints above seabed. Rigid centraliser on first two joints below wellhead.

•

MLS EQUIPMENT IS BEING USED Centralisers on first two joints inside the 20" shoe. Spring centralisers on first two joints below hanger assembly. Rigid centralisers on first two joints above the hanger assembly. Rigid centralisers on first two joints below the wellhead.

4.3

9 5/8" Casing To determine centralisers knowledge of actual hole calliper data is available, Figure 2. If the well force centralisation is required.

required in open hole section, use Figure 3. In the event that there is no size, programme greater than 80% stand-off where isolation is critical. If programme to achieve greater than 70% after allowing for hole OD using in any section exceeds 3,500 lbs per joint, rigid centralisers must be used if

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NO MLS EQUIPMENT BEING USED Rigid centraliser one joint below the wellhead.

•

MLS EQUIPMENT IS BEING USED Centralisers on first 4 joints inside previous casing. Spring centralisers on first two joints below the hanger assembly. Rigid centraliser on first two joints above the hanger assembly. Rigid centraliser one joint below the wellhead.

4.4

7" Casing and Liner

4.4.1

Casing Spring centraliser two per joint to 10 joints above the reservoir, then one per joint to 30m above planned TOC in 9 5/8" - 7" annulus. Centralisation above TOC as for 9 5/8".

4.4.2

Liner Non-Rotating Two straight bow centralisers per joint, this will ensure casing stand-off greater than 80%. Stop collars must be installed whilst pipe is on the deck to minimise lost rig time. Rotating If greater than 80% stand-off can be achieved, there will not be any significant benefits to be obtained from rotation. However, where the mud and cement weights are close (less than 2 ppg), or displacement rates are constrained to less than 3 bbl/min or less than 2 centralisers per joint are run, rotation should be considered. In this case a welded bow centraliser must be used. The minimum rate at which rotation is likely to benefit is 10 rpm.

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FIGURE 1 Centralisation Chart for 13 3/8" Casing with Weatherford ST IV Centralisers in 17 1/2" O.H.

• • • • •

90

• 20 ft. SPA CI

NG

• 2 PER JOINT • 30 ft. SP AC ING • • 4

80

0f

t. S

PA

CI

70

NG

• 1 PER JOINT

• 50 ft.

•

G

IN

STAND-OFF (%)

AC

SP

60

•

50

•

60

40

ft. ING

AC

SP

30

ACI

t. SP

80 f

•

NG

20

10

MINIMUM STAND-OFF FROM 14 3/8" COUPLING

1 EVERY SECOND JOINT

HOLE ANGLE (degrees)

0 0

10

20

• 30

40

50

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FIGURE 2 13 3/8" Centralisation v. O.H. Diameter

90

80

70

STAND-OFF IN GAUGE HOLE

•


•

•

• •


STAND-OFF (%)

60

• • •

•

50 •

40

•

•

•

• •

30

20

10

OPEN HOLE DIAMETER (inches)

0 17

18

19

20

21

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FIGURE 3 Centralisation Chart for 9 5/8" Casing with Weatherford ST III Centralisers in 12 1/4" O.H.

• • •

• 20 ft. SPACING

90

80

• 2 PER JOINT

• 30 ft. SP AC ING

•

•

70

• 40

•

ft. SP

STAND-OFF (%)

G

IN

AC

60

• 1 PER JOINT

50 • 40

MINIMUM STAND-OFF FROM 10 5/8" COUPLING

• 50

30

ft. S

CING

G

SPA

CIN PA

60 ft. 80 ft. S

20

G PACIN

10

• 0

• HOLE ANGLE (degrees)

• 0

10

20

30

40

50

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FIGURE 4 9 5/8" Centralisation v. O.H. Diameter

STAND-OFF (%)

90

80

•

70

•

60

•

•

•

• •

50

• •

40

• • •

30

20

10

OPEN HOLE DIAMETER (inches)

0 12

13

14

15

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PREPARATION & RUNNING 30" CONDUCTOR & STAB-IN CEMENT STINGER ASSEMBLY

1.

SPACE-OUT AND RUNNING ORDER

1.1

Normally 30” conductor will be run to approximately 60m (five joints) below seabed. The conductor should be spaced out to place the top of the Dril-Quip Quick Jay Box at 1 (one) metre above the seabed. This depth will be the definitive depth for the conductor space-out. The mudline hanger suspension ring joint should be located one full joint below the seabed. This will allow further casing strings to be backed out of their mudline hangers during abandonment/suspension, avoiding casing cutting, but still complying with DEn depth restrictions above seabed.

1.2

The following running order should be used for 1” wall conductor: 30” OD x 1” WT shoe joint w/stab-in float shoe x Lynx SA pin up. 2 x 30” OD x 1” WT conductor joint w/Lynx SA box down x Lynx SA pin up. (Numbers may vary depending on programmed 30” shoe depth.) 30” OD x 1” WT MLH suspension ring joint w/Lynx SA box down x Lynx SA pin up. 30” OD x 1” WT crossover joint w/Lynx SA box down x Quick Jay box up. 30” OD x 1” WT landing joint w/Quick Jay pin down x Lynx SA pin up. 30” OD x 1” WT conductor joints w/Lynx SA box down x Lynx SA pin up. (Numbers to suit water depth).

2.

PREPARATION

2.1

Inspect all lip and “O” ring seals and seal areas on the Lynx SA and Quick Jay connectors. If there is any doubt as to the integrity of the seals, remove and discard them. Clean the seal housing and seal face using a steam gun, high pressure water gun or degreasing agent. Ensure seal housings are dry and free from degreasing agent before installing new seals. A light coating of grease on the seals will assist in installation. Lightly grease seal and seal areas. Note that 2 “O” ring seals should be installed on the Quick Jay pin.

Note: If for any reason the 30” conductor needs to be retrieved, then all seals should again be inspected and replaced if required. Ensure adequate spare seals are on board to re-run the conductor assuming all seals would need to be replaced. 2.2

All Lynx SA connectors (as a minimum those above the Quick Jay connector) should have anti-rotation dowells in the box and corresponding slots in the pin to allow for disconnection at the Quick Jay box.

2.3

Check ID’s of the mudline hanger suspension rings to ensure a 26” bit can pass. Accurately measure the distance from the top shoulder of the mudline hanger suspension ring to the shoulder of the Lynx SA pin above. This measurement will be required for subsequent wellhead/mudline hanger space-out calculations.

2.4

Ensure that no connections coincide with 30” cutting depths for the jack-up, both for installation of the diverter system or subsequent cut for installation of starter wellhead on first casing string.

2.5

Check the 30” stab-in float shoe and if appropriate the installation of the debris plug.

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PREPARATION & RUNNING 30" CONDUCTOR & STAB-IN CEMENT STINGER ASSEMBLY

Ensure that the stab-in stinger is compatible with the 30” stab-in guide shoe and seals are in good condition (spare seals should be on board, if required). 3.

RUNNING CONDUCTOR

3.1

Run conductor in correct order as indicated above.

3.2

Fill the conductor to sea level with seawater after running each joint.

3.3

When making up the Quick Jay connector, install locking wedge and attach a cable to be run back to surface. (Once the 30” is landed this cable should finally be secured below the rig floor until required when suspending the well.)

3.4

Ensure ROV or divers are deployed to monitor and assist stabbing of the guide shoe into the 36” hole.

Note: a)

Whenever possible a large ROV capable of nudging the conductor should be available so that stabbing of the 30” into the 36” hole is less dependent on slack water.

b)

It is normal to use divers in water depths of 50m or less.

3.5

Run the conductor to the required depth (top of Quick Jay box, 1m above seabed) and confirm position above seabed with ROV or divers. Land conductor in slips.

3.6

If necessary cut conductor so that stick-up is +/- 1m above rig floor and cut eyes to allow slings to be attached.

3.7

Make up stab-in stinger to first joint of drillpipe and install 5”/30” balloon centraliser 1m above the stabin sub. Run first joint into conductor.

3.8

Rig up and run remainder of drillpipe cement stinger assembly. If there is no latch mechanism on the stab-in stinger, it may be necessary to use HWDP for the cement stinger to ensure the cement stinger assembly cannot be pumped out of the float shoe. The preferred method is to use a 30” spider adapter plate w/bowl and slips. Alternatively a “C” plate w/double elevators can be used.

3.9

Refer to Section 3100/FIX for details of stabbing in, circulating and cementing.

3.10

Pull drillpipe cement stinger assembly and rig down elevators.

3.11

Pick up the 30” conductor only enough to recover the 30” slips and hold in place until surface samples have set. (If the conductor was cut above the rig floor, then slings will be required to lift the conductor.)

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PREPARATION AND RUNNING 30" CONDUCTOR/PGB Dril-Quip SS15 System

1.

GENERAL

1.1

On an exploration well a four joint conductor is normally run, placing the shoe at ± 50m BSB. In instances where it is planned to run the Marine Riser/30” hydraulic latch assembly after setting the conductor, the shoe depth may be deepened to ± 75m BSB to enable drilling the 26” hole with returns to surface.

1.2

The standard conductor string comprises:

1.3

Shoe Joint

:

30” x 1” WT Grade X52 - 12m Welded Guide Shoe (a welded float shoe may be considered) Vetco RL-4 or Lynx SA Pin

Inter Joint

:

30” x 1” WT Grade X52 - 12m Vetco RL-4 or Lynx SA Box-Pin

Inter Heavy Wall Joint

:

30” x 1 1/2” WT Grade X52 Vetco RL-4 or Lynx SA Box-Pin

W/Head Joint

:

30” x 1 1/2” WT Grade X52 - 9m Vetco RL-4 or Lynx HD Box - Drilquip SS15 Housing

The conductor is run with the Permanent Guide Base (PGB) attached. The PGB is supplied with the following standard features: Two mountings for slope indicators. Guide post tops with Regan latch profile. Annulus cementing guide. Socket attachment for guide posts. Basket for sonar beacon.

1.4

All the conductor joints are supplied with 2 lifting/handling lugs which facilitate handling and allow the joints to be landed on the rotary table to make up the next joint.

Note: See Section 5000 for details of wellhead equipment. 2.


Item

Dril-Quip Part No.

PGB (2 off). Conductor string as 1.1 (2 off). Spare O rings for connectors. 30” wellhead housing for the 18 3/4” Rigid Lockdown Wellhead Housing. 30” elevator (2 off). 50 ton strops and shackles. 30” rotary slips (2 off). 30” Cam actuated running tool (6 5/8” Box/4 1/2” IF Pin).

342059

3.

PREPARATION

3.1

Depending on the connectors used, check for: a) b) c)

Condition of “O” rings. Lock ring free to move in groove. Ensure alignment lug is not loose.

380010

420000

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PREPARATION AND RUNNING 30" CONDUCTOR/PGB Dril-Quip SS15 System Thread damage.

3.2

Lightly grease the connectors (do not use metallic dope - i.e. pipe or casing dope).

3.3

Tack weld four small chain links to a steel band, restricted on vertical movement by lugs (this allows conductor to rotate without snagging/snapping softline guides), ± 1.5m and 3m above the shoe.

3.4

One joint of drillpipe or fibre-glass pipe to be made up below the running tool as a cement stinger.

3.5

Record the serial numbers of all subsea equipment run.

3.6

Make up 30” running tool and rack back in derrick on drifted HWDP.

3.7

Mark the position of the hole with two Grimsby buoys tethered to clump weights perpendicular to the rig heading.

4.

RUNNING CONDUCTOR

4.1

Position the PGB on the cellar deck hydraulic beams and secure the guidelines into the guideposts. Tension the guidelines to 5000 - 7000 lbs equal all round. Ensure that the guideposts are marked 1, 2, 3, 4 clockwise with No. 1 being forward starboard position.

4.2

Pick up shoe joint, lower through the rotary table and stab through the PBG. Land on RT.

4.3

Attach softline to the guide rings on the shoe and through small shackles on the guide wires to provide guidance for the shoe. Note that it is better to have the guide ropes shorter rather than longer.

4.4

Pick up the second joint and suspend above the RT. If there is a lock ring groove in the box, check that it is free of debris.

4.5

If required align orientation/non-rotation key and stab second joint into shoe joint.

4.6

Cut off the landing pad eyes on the shoe joint and continue to run the string in this way up to and including the wellhead joint.

Note: Clearly mark the wellhead joint with paint marks every 0.5m from wellhead to assist observations when landing the conductor at seabed. 4.7

Make up the 30” wellhead housing to the conductor string. Pick up the running tool and lower the running tool into the 30” wellhead housing. Align and engage the 4 anti-rotation alignment pins on the OD of the running tool into the mating slots in the housing. Rotate the running tool approximately 5 turns to the left. This moves the split lock ring out to engage into its mating profile inside the 30” housing. Turn the running tool back to the right 1/8th of a turn. Do not exceed 1/4 turn. Confirm the running tool is properly made up by checking the height of the indicator rod - it should measure 7/8” from the top plate of the running tool.

4.8

Pick up the running tool and wellhead housing assembly and make up onto the conductor string. Land off housing assembly at RT.

4.9

Land the 30” housing/running tool assembly in the PGB ensuring engagement of the 4 anti-rotation alignment bolts in the PGB. Make up the 8 anchor bolts which move the lockdown ring out into the mating profile on the 30” wellhead housing OD.

4.10

Remove the 30” running tool from the wellhead housing.

BP EXPLORATION


Section

:

2100/SEM

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:

4 (1/94)

Page

:

3 of 8


Make up and run the inner cementing string through the conductor. The cementing string should be as follows: 2 joints x 5 1/2” fibreglass tubing X/O 5” DP pup 5” DP Make up the stinger to the running tool and the running tool/stinger assembly to the wellhead housing.

Note: The length of drillpipe should be such that the bottom of the inner string is 15m above the 30” shoe when the running tool is made up to the wellhead housing. 4.12

Circulate through the running tool to ensure circulation through the shoe.

4.13

Replace 2 of the flowby plugs with the fill and vent ball valve assemblies (in the open position).

4.14

Retract the spider beams and RIH the 30” wellhead housing and PGB on HWDP until the running tool is just below the splash zone and stop. Circulate and observe that all the air is displaced from the conductor.

4.15

When the casing is vented of air, pick back up clear of the splash zone and close the ball valves.

4.16

Run the 30” wellhead housing and PGB on 5” HWDP. Stab into the open hole (or TGB if run) monitoring the operation with the ROV or SS TV camera.

4.17

When the last joint of the running string is made up, activate the motion compensator to support the weight of the complete conductor assembly.

4.18

Set the PGB 1m above seabed (if a TGB is used, this will place the PGB gimbal on the TGB guide cone without loading the TGB).

4.19

Check the orientation and angle of the PGB. The maximum allowable angle for SWOPS wells is 1 degree and generally 2 degrees for other wells. If necessary, manoeuvre the rig to achieve the required verticality. If this is not possible, then the conductor will have to be retrieved and the hole rereamed.

4.20

Cement the conductor to seabed with the string weight taken on the compensator. Observe cement returns at seabed with the ROV or SS TV (see Section 3150/SEM).

4.21

Wait on cement until surface samples are hard, maintaining the verticality of the PGB. Once hard, slack off string weight observing the conductor to ensure no movement.

4.22

Adjust the motion compensator to support the weight of the running string, cement stinger and running tool with a 10,000 lbs overpull. Rotate the running string 5 turns to the right. When the split lock ring retracts from its mating profile in the wellhead housing, the motion compensator will stroke shut pulling the running tool from the 30” wellhead housing.

4.23

Pull the landing string to place the bottom of the cement stinger +/- 3m inside the wellhead.

4.24

Flush the wellhead and PGB with the stinger, observing with the ROV.

BP EXPLORATION


Section

:

2100/SEM

Rev.

:

4 (1/94)

Page

:

4 of 8


5.

RUNNING CONDUCTOR WITH TITUS AUTOMATIC TOP-UP

5.1

General The cement top-up system is run as an integral part of the guide base and top conductor joint. After performing the primary cementation, a shear sub is opened allowing cement to be diverted from the landing string to a cement distribution ring 9m below seabed. This allows a top-up cement job to be performed while waiting for the primary cement job to harden. When using the system the 30" shoe should be fitted with a float valve.

5.2

5.3

System Description a)

The 30" wellhead housing is shipped with a cement distribution ring and pipework already fitted to the conductor joint. The pipework is fitted with a quick connect coupling.

b)

The guide base is shipped with a cement hose male stab and 3m of connecting hose already fitted. The connecting hose is fitted with a quick coupling compatible with the pipework on the 30" wellhead housing/conductor joint.

c)

A cementing swivel with internal shear sub and 2" 1502 Weco side outlet is supplied for installation above the 30" running tool.

d)

A grouting hose with 1502 Weco fitting and female stab fitting is required. The female stab is equipped with a latch allowing ROV disconnect.

Running Procedure a)

Run the 30" conductor and latch into guide base ensuring that the 3m connecting hose will reach the pipework on the side of the 30" housing. Connect the quick latch coupling on the connecting hose.

b)

Make up the cementing stinger and 30" running tool. Install the cementing swivel above the running tool.

c)

Make up the running tool to the 30" housing. Connect the grouting hose to the cementing swivel side outlet. Connect the other end to the stab on the guide base.

Note: Check with ROV Supervisor that the lock handle on the female sub is suitable for ROV release. d)

Run 30" conductor until housing is at sea level, filling casing with seawater. Pull back to give a 6' air gap at top of conductor and close bleed valve on running tool.

Note: This is to reduce the tendency for the 30" housing running tool to become pressure locked on top of the conductor, by the hydrostatic head of seawater. e)

Continue running conductor as per programme.

BP EXPLORATION


Section

:

2100/SEM

Rev.

:

4 (1/94)

Page

:

5 of 8


Automatic Top Up Cement System Schematic Conductor Running String

1502 WECO Connection 1 1/2" Nominal Flexible Hose

Cementing Swivel X-Over 30" Running Tool

ROV Operated Quick Connect Coupling

Permanent Guide Base 1 1/2" Nominal Flexible Hose Quick Connect Coupling

Fixed 1 1/2" Nominal Diameter Cement Injection Line Cement Distribution Ring Welded to 30" Conductor Note: Float Shoe Required on Conductor

S.Morrison, Dec. 1993, 01110047

BP EXPLORATION


Section

:

2100/SEM

Rev.

:

4 (1/94)

Page

:

6 of 8


PGB for Cement Top-Up System : Assembly/Weldment ,,,, ,,,, ,,,, ,,,, ,,,, ,,,, ,,,, ,,,, ,, ,, ,,,, ,,,, ,,,, ,,,, ,,,, ,,,, ,,,, ,,,, ,,,, ,,,, ,, ,, ,, ,, ,,,, ,,,, ,, ,, ,, ,, ,, ,, ,, ,, ,, ,, ,, ,, ,, ,,,,,,,,,,,, , , , , , , , ,,,,,, ,, ,,,,,,,,, ,,,,,,,,,,,, ,,,,,,,,,,, ,,,,,, , , , , , ,,,,,, , , , , , , , , , , , , ,,,,,, ,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,, ,,,,,, ,,,,,,,,,,,,,,,,,,,,,,,,,,,,,, ,, ,, ,, ,,

Detail of Grouting Operation Position of Webs & Support to Suit Elbow

, , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , , ,,,,,,,,,,,,,,,,,,, ,

11' 1 5/8" (133.62)

9' 10 1/16"(118.06") 8' 5 13/16"(101.81")

41.25" Dia. 37.285" Dia. 36.29" Dia.

,,,,, , ,,,,, ,

S.Morrison, Dec. 1993, 01110075

, , ,,, ,,,, ,,, ,,,, ,,,, ,,,, ,,,,

Gimbal is Optional

BP EXPLORATION


Section

:

2100/SEM

Rev.

:

4 (1/94)

Page

:

7 of 8


Subsea Wellhead Systems Cement Top-up System ø30" Casing Assembly

Stressless Stamp Dril-Quip P/N 4 - 400182 - 02 Rev 1 S/N Assembly

, , , ,, , ,, , ,, , , , , ,, , , ,, , , , , ,, , , ,, , , , , , , ,, , , , , ,, , , , , ,, , , ,, , , , , ,, , , , , , , ,, , , , , ,, ,

2

, , , , , , , , , , , , , , , , , ,,, ,

See Detail 'A'

Notes:

,,,,,, ,,,,,, ,,, ,,,,,,,,,,, ,,,,, ,,,,,,,,,,, ,,,,, ,,,,, ,,,,, ,,,,,,,,,,, ,,,,, ,,,,, ,,,,, ,,,,,,,, ,,,,, ,,,,,,,,,,, ,,,,, ,,,,, ,,,,,,,, ,,,,,, ,,,,,,

1 Stamp latest revision letter from parts list

,, ,, ,, ,, ,, ,,

,,, , ,, , ,, ,, , , ,, , ,, ,, , , ,, , ,, ,, , , ,, ,, , , , , , ,, ,, , , ,, , ,, ,, , , , , , , ,,, , , , , , , ,, ,, , , ,, ,, , , , , ,, ,, , , , , , , , , , ,, ,, , , , , , ,,, ,

, , , , , , , , , , ,, ,,, ,,, ,,,,, , ,, ,, , ,,,,,,, , ,,,, ,,,,,, , ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,,

,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,,

,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,,

Detail 'A'

1

S. Morrison, Dec 1993, 01110048

,,,,,, ,,, ,,,,,, ,,, ,,,,,, ,,,,,,

,, ,, ,,

BP EXPLORATION


Section

:

2100/SEM

Rev.

:

4 (1/94)

Page

:

8 of 8

PREPARATION AND RUNNING 30" CONDUCTOR/PGB Dril-Quip SS15 System 9.875 7.875

S.Morrison, Dec. 1993, 01110049

,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,, ,,,,, ,,,,,,, ,,,,, ,,,, ,,,,, ,,,,,,, ,,,,, ,,,, ,,,,, ,,,,,,, ,,,,, ,,,, ,,,,, , ,,,,, ,, ,, ,,,,, ,,,, ,,,,, , ,, ,,,,, ,, ,,,,, ,,,, ,,,,, , ,, ,,,,, , ,,,,, ,,,, , ,,,,, , ,,,,, ,, ,,,, ,,,,, ,,,,, ,,,, , ,,,,, ,,,,, ,,,, ,,,,, ,,,,, ,,,, ,,,,, ,, ,,,,, ,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,,

34.250

,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,,,,,,,, , ,,,,,, , , , , , , ,,,,,, , , , , , , , , ,,,,,, ,,,,,,,,,,,, , , , , , , , ,,,,,, , , , , , , , , ,,,,,, ,,,,,,,,,,,, , , , , , , , ,,,,,, , ,,,,,,,,,,,, , , , , , , , ,,,,,, , ,,,, , , , , , , ,,,,,, , ,,,,,,,,,,,, , ,, , , , , , , ,,,,,, , ,,,,,,,,,,,, , ,,,, ,,,,,, ,, , , , , , , ,,,,,, , ,,,,,,,,,,,, , ,,,, , , , , , , ,,,,,, , ,,,, , , , , , , ,,,,,, , , , , , , , ,,,,,, , ,,,, , , , , , , ,,,,,, , , , , , , , ,,,,,, , ,, , , , , , , ,,,,,, , , , , , , , ,,,,,, , , , , , , , ,,,,,, , , , , , , , ,,,,,, , , , , , , , ,,,,,, ,, , ,,,,,,,, ,,,,,, , ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,, Box & Pin Ends ,,,,,, 4 1/2" I.F. Thread ,,,,,, ,,,,,, ,,,,,, ,,,,,, ,,,,,,

BP EXPLORATION


Section

:

2105/FIX

Rev.

:

0 (8/91)

Page

:

1 of 3

CUTTING AND PREPARATION OF CASING TO ACCEPT WELLHEAD SPOOLS

Casing can be cut externally using split type (wrap-around) precision cutting equipment. The cutting equipment is not complicated to use. The drilling crew, after initial instruction and demonstration by a service company, caneasily accomplish a satisfactory cut. Care must be exercised in handling the equipment and time taken to ensure the cutter is correctly clamped and “squared up” to the casing joint. Figure 1 illustrates the casing cutter secured to 2 different styles of flanges.

2.

KEY POINTS IN ACHIEVING A SATISFACTORY CUT

2.1

All equipment to be thoroughly checked long in advance of cutting operation. Check rotating parts are debris-free and cutting tools in perfect condition.

2.2

Clear all debris from working area and ensure good access to wellhead.

2.3

Take particular care not to damage or impact any part of the cutting equipment when offering split rings around casing.

2.4

Take extra time to get cutting equipment perfectly “square” around the casing.

2.5

Check height of casing cut to wellhead flange corresponds to “swallow” in throat of spool to be added. Ensure seal ring dimensions have been taken into consideration when cut-off height is checked. N.B. Drilling programme should state casing cut-off heights.

2.6

Prior to commencing cut, BP Representative must check casing cut-off height with casing cutter fully clamped up.

3.

DESCRIPTION AND OPERATING PRINCIPLE OF EXTERNAL CASING CUTTER

3.1

The casing cutter has two main sections - the body and the mounting flange. The body rotates and carries the cutting tools. The mounting flange carries the air powered drive and secures the equipment to the wellhead flange. Both sections of the machine are split into 2 halves, allowing the casing cutter to be “wrapped” around the casing. The mating faces of each half are accurately machined for location to each other and dowelled. The air motor located on the mounting flange drives the inner body through a spur gear into a split gear which is mounted on the outside diameter of the inner body.

Note: Ensure that the cutter is provided with a cover to protect the point where the drive pinion engages the toothed ring on the rotating table. Two machine tool slides are mounted on the top face of the inner body 180 degrees apart. These slides carry cutting tools to cut through the casing and to form a chamfer on the outside leading edge of the remaining casing stub. One tool has a vee shaped cutting point to break the surface of the casing slightly ahead of the cutting square pointed tool. A chamfering tool is mounted on the underside of the cutting tool. This forms a chamfer immediately the casing is cut through.

BP EXPLORATION


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2105/FIX

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4.

CUTTING PROCEDURE

4.1

Establish casing cut-off height. Pre-set and lock the cutting tools on the machine slides.

Note: It is the responsibility of the Drilling Supervisor to check that the cut-off height has been correctly set. 4.2

Position the cutter in 2 halves, on either side of the wellhead prior to running casing. Cover the equipment with a tarpaulin to prevent debris or mud falling on top of the gear whilst running and cementing the casing.

4.3

With the casing hung off in the wellhead, remove the fluid inside the casing from the wellhead to the rotary table. This can be done by: a)

Run pipe into the casing to displace enough fluid down to the wellhead; or

b)

If a permit has been obtained, burn a hole in the casing 2 ft above the wellhead and allow the fluid to drain out.

4.4

Secure the casing cutter on the wellhead flange and to the casing. The cutter, depending on the wellhead type, is secured by either a clamp or is bolted.

4.5

Check the machine is rotating concentrically and the final cut-off stub height is correct.

4.6

Cut the casing. If the casing cutter is of the type which requires the cutting tools to be manually fed, then position a man close to the air supply. If a problem occurs and safety is compromised the air supply can quickly be turned off. Patience and time are required to carry out the cutting operation. Feed the cutting tools slowly to achieve a neat cut rather than a tear.

4.7

Once the cut has penetrated the casing, stop the machine and allow any excess fluid to drain out. Complete the cutting operation.

4.8

Remove the cut casing from the rotary table.

4.9

Remove the casing cutting equipment.

4.10

The final cut may have to be gently dressed off with a grinder to remove any razor edges which may damage the next casing head spool seals.

4.11

Clean all the cutting equipment and pack ready for return to the onshore supplier.

Note: It is the responsibility of the Drilling Supervisor to ensure the equipment is cleaned and returned onshore properly. Any broken or missing equipment should be recorded and the supplier informed.

SUBJECT:

BP EXPLORATION

DRILLING MANUAL

FEED ARRANGEMENT BEARING SURFACES

SPLIT GEAR MOTOR PINION

Page

Rev.

Section

:

:

:

3 of 3

0 (8/91)

2105/FIX

MOTOR AND GEARING

IDLER GEAR

13 3/8" CASING

911208/14

FIGURE 1

5000 PSI MSP WELLHEAD S137 CONNECTION

TOOL SLIDE

SPLIT TYPE CASING CUTTING MACHINE 13 3/8" CASING CUTTING

13 5/8" 5000 PSI MSP API FLANGE


CUTTING TOOLS

BP EXPLORATION


Section

:

2200/FIX

Rev.

:

7 (10/90)

Page

:

1 of 2

PREPARATION AND RUNNING 20"/18 5/8" CASING - GENERAL

1.

PREPARATION

1.1

Carry out General Casing Checks as per Section 2000/GEN.

1.2

If inner string cementing is programmed, make up and rack back cementing stinger, see Cementing Section 3200/FIX.

1.3

a)

If it is programmed to run the casing through the stack and diverter, remove the diverter packer.

b)

If it is programmed to nipple down the stack and diverter, it may be necessary to adjust the compensator for loss of the riser hydrostatic head. Prior to rigging up; drain riser, flowcheck for 15 minutes. Nipple down 21 1/4” riser and BOP. It is essential that the fluid level be continuously monitored and, if necessary, topped up using a fill-up line.

1.4

Rig up to run surface casing.

1.5

Ensure that all platform and rig specific criteria, landoff heights, wellhead orientation and conductor slump loads are known and met.

2.

RUNNING

2.1

Position the float collar one joint from the shoe.

2.2

If buttress casing is in use, Bakerloc all connections up to and including the pin connection on the third joint of casing. If any other type of connector is in use, do not use Bakerloc; clean threads and ensure they are free of grease. Make up connectors with light oil to maximum torque, as specified by the manufacturer.

2.3

Run the casing, installing centralisers as per Section 2010/GEN. Run the casing slowly to prevent surging the hole, monitor returns for losses, if practical. Fill the casing every joint.

2.4

Make up the wellhead housing or wellhead joint as required. On platforms refer to Section 5000 for Specific Notes on wellhead make-up and casing land-off and space-out details. Attempt to keep the stick-up at the rotary table to a maximum of 1m for ease of running the cement stinger.

Note: - Ensure that a casing collar is not situated at the casing cutting depth. - Do not rotate the casing as this might back out the running tool. 2.5

Land-off casing, washing the last joint in wherever practical.

2.6

Mark off casing datum at rotary and/or bell nipple.

2.7

Run cementing stinger as per Cementing Section 3200/FIX or 3210/FIX. Rig up to cement casing.

2.8

Drain riser. On jack-ups the conductor must remain full so that leaking seals on the cement stinger can be detected.

2.9

Circulate hole prior to cementing. Flowcheck hole.

2.10

Cement the casing as per Cementing Section 3200/FIX or 3210/FIX. Check for backflow. If backflow occurs, hold pressure until no flow occurs. Keep this time to a minimum to avoid problems circulating the 20”/30” annulus.

2.11

Flush stinger, at maximum pump rate.

2.12

On platforms, refer to Platform Specific Sections.

BP EXPLORATION


Section

:

2200/FIX

Rev.

:

7 (10/90)

Page

:

2 of 2

PREPARATION AND RUNNING 20"/18 5/8" CASING - GENERAL


Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

1 1 1 1 1 set 1 4 1 1 1 1 lot 1 1 1 As required As required As required 1 set 1

26 27 28 29 30 31 32 33 34 35 36

1 1 lot 1 1 1 set 1 1 lot 1 1 1 1 lot

20”/18 5/8” safety clamp. 20”/18 5/8” side door elevators. 20”/18 5/8” single joint elevators. 20”/18 5/8” hand slips. Casing tongs c/w necessary jaws. 20”/18 5/8” circulating swedge with Lo-torc valve. 20”/18 5/8” Klampon protectors. 20”/18 5/8” power tong (not required for RL-4S). Power unit for tong (not required for RL-4S). Casing spool running tool if required. 20”/18 5/8” casing and pups as required. 20”/18 5/8” landing joint or MLH/running tool assembly. 20”/18 5/8” float shoe. 20”/18 5/8” float collar. 20”/18 5/8” centralisers. Stop collars c/w spiral nails. Centraliser nails. Split casing bushing for rotary table. 20”/18 5/8” casing drift. Bakerlok Set. Casing dope. Cementing stinger sub (4 1/2” IF box conn). “O” rings for cementing stinger sub. 20”/18 5/8” x 5” spring bow centraliser. 20”/18 5/8” casing plate for running cementing stinger (guide plates on outside). 5” drillpipe slips. Casing head housing equipment as required. 20”/18 5/8” wear bushing, if required. Wear bushing running tool, if required. Cementing darts. 4 1/2” IF pin x 2” well plug dropping head. Spare “O” rings for 20” connections (if required). Hilti gun complete with spare cartridges (for RL-4S connections - if required). 18 5/8”/20” water bushing (4 1/2” IF box). 20”/18 5/8” BOP test plug with spare seals. Cement and chemicals.

1 4 1 1


BP EXPLORATION

SUBJECT:

Section

:

2200/SEM

Rev.

:

4 (09/96)

Page

:

1 of 4

PREPARATION AND RUNNING 20"/18 5/8" CASING Dril-Quip SS15 System

1.0

The 20” surface string is normally set around 600m BRT. The exact setting depth will be specified in the drilling programme. The casing used for the surface string is 133 lb/ft, X56 with Vetco RL-4S connections.

1.1

The float equipment (usually consisting of a double valve shoe) is normally sent out made up to the pipe and the 20” string typically comprises: Shoe Joint

:

20” 133#; double valve shoe - Vetco RL-4S

Inter Joints

:

20” 133#; Vetco RL-4S pin/box

X/O Joint

:

20” 133#; Vetco RL-4S pin - RL-4S pin

W/H Joint

:

Drilquip SS15 18 3/4” (20” OD x 1.5” WT) Extension ± 2m long with 0.812” WT RL-4S box

Note: 1.

A float collar will be run if a wiper plug is to be used. In this case the FC joint will be: 20” 133# VRL-4S pin - VRL-4S box.

2.

Depending upon application in some wells 20” x 1” WT extension joints are run to provide increased bending resistance.

See Section 5000 for details of wellhead equipment. 2.0


Item

Dril-Quip Part No.

Shoe joint (2 off). F. Collar joints (2 off) (if required). Intermediate joints, X56, 133# (incl. spare joints). Wellhead joint with 18 3/4” rigid lockdown wellhead (2 off). 20” springbow centralisers/stop rings (6 off). 20” casing rotary slips. 20” elevator. Spare “O” rings for RL-4S connector. Hydraulic rigid lockdown tool and 18 3/4” wellhead running tool assembly (6 5/8” Reg Box/4 1/2” IF Pin). Spare “O” rings for R. tool. Rigid lockdown actuating dart. Bleeder sub lock plate. 20” casing spear. 20” circulating head with X/O. 20” casing tong and crew. 18 3/8” nominal bore protector. 18 3/4” multi-purpose running tool. 18 3/4” adaptor for multi-purpose running tool: Running Pulling Hotline. 3.0

380530

346014/420002

852286

420007 420010

PREPARATION 1.

Perform the general checks as outlined in Sections 2000/GEN and 2900/GEN.


SUBJECT:


Section

:

2200/SEM

Rev.

:

4 (09/96)

Page

:

2 of 4


2.

Swab/surge pressures should be calculated for various running speeds, and an acceptable running speed selected to ensure that the formation breakdown pressure is not exceeded.

3.

Draw a graph of casing joints run versus hookload. Use this graph to check if the casing is being filled correctly as it is being run.

4.

Remove thread protectors, clean and lightly grease the connections (do not use metallic compounds such as pipe/casing dope).

5.

Check the condition of the “O” rings and replace if necessary.

6.

Replace the protectors prior to picking up the pipe.

7.

Tack weld 4 chain links to steel bands restricted from moving vertically by lugs 1m and 3m above the float shoe for soft line guidance as with the 30”.

8.

Visually check the shoe joint and float joint if run to ensure no debris inside.

9.

Ensure that the wellhead running tool and landing string have been drifted to allow the modified 2.593” launching dart to pass through. The ID of the running tool is 3”. A gauge is provided by Dril-Quip for checking the dart dimensions.

10. Install one springbow centraliser 2m above the shoe and one 2m above the F. collar if run. 11. Perform the following additional checks: i)

ii)

18 3/4” Rigid Lockdown Wellhead Housing a)

Visually inspect the anti-rotation holes on the top of the housing.

b)

Check the condition of the ring gasket seal area located at the top of the 18 3/4” wellhead.

c)

Check the “O” ring on the OD of the retainer nut.

d)

Visually inspect the lockdown ring mechanism around the centre section of the wellhead OD.

e)

Check that the 10 shear pins below the lockdown mechanism have been correctly installed.

Hydraulic Rigid Lockdown Tool and 18 3/4” Wellhead Running Tool a)

These two tools will be supplied to the rig made up as one unit. Make up a 6 5/8” Reg pin x 4 1/2” IF box crossover and an S135 drillpipe pup joint to the top of the running/ lockdown assembly for ease of handling. This can be done on the pipe deck.

b)

Visually inspect all hoses and fittings on the unit.

c)

Check that the position indicator plate functions correctly.

d)

Check that the pressure gauge which is plumbed into the hydraulic circuitry between the 5 gallon accumulator and the hydraulic cylinder is showing between 700 and 800 psi.

e)

Install the bleeder sub lock plate between the bleeder sub and control sub.

f)

If the cement is to be displaced with cement wiper plugs, check that a modified 2.593” cement plug releasing dart is available. The minimum clearance through the hydraulic lockdown tool is 2.62”.


SUBJECT:


Section

:

2200/SEM

Rev.

:

4 (09/96)

Page

:

3 of 4

PREPARATION AND RUNNING 20"/18 5/8" CASING Dril-Quip SS15 System g)

Perform a pressure/function test of the hydraulic rigid lockdown tool in its transportation skid. Ensure that the full stroke of the tool is 2 1/2”.

12. Whenever possible efforts should be made to make up the lockdown/ running tool, 18 3/4” wellhead with wellhead joint and plug launching mechanism prior to running the casing string. The assembly will normally be made up in the rotary table and laid down on the pipe rack ready for use. Making Up the Assembly

4.0

a)

Make up the plug launching mechanism and a pup joint below the lockdown/running tool. Ensure that the cement plug is spaced out to be in the wellhead extension. Once completed lay down the assembly on the pipe rack.

b)

Set the 18 3/4” wellhead in the RT on 30” bushings or a split plate.

c)

Pick up the lockdown/running tool and install the wiper plugs on the plug launching mechanism.

d)

Make up the running tool into the wellhead.

e)

Once made up rotate the drillpipe stem of the lockdown tool +/- 5 turns to the left to engage the split lock ring. Back out the lockdown tool 1/8th of a turn to ensure easy release after the cement job. Confirm the running tool is properly made up by checking the height of the indicator rod. It should measure 7/8” from the top plate of the running tool.

f)

Ensure that the position indicator plate on the sleeve of the lockdown tool is in the fully raised position. Measure 2 1/4” from the bottom of the plate and mark with paint to confirm stroke of the actuator sleeve.

g)

Lay down the wellhead and extension with the running tool on the pipe rack.

RUNNING THE CASING 1.

The torque range for make-up of the 20” RL-4S connector is 18000 - 25000 ft lbs. If it becomes necessary to break out an RL-4S connector, the anti-rotation tab can be prised out with a screwdriver (the torque required to break out a single tab is 12,000 ft lbs). Refer to Section 5104/GEN for data on RL-4S connectors.

2.

After making up the float shoe joint and one joint of casing, check the float equipment is clear by flushing through with water. Confirm float equipment functioning. The four anti-rotation tabs on the float shoe joint and the one above it should be locked with the Hilti gun. Ensure standard hotwork procedures are followed.

Note: Do not apply threadlocking compounds to these connectors. 3.

Attach soft line guide ropes to the shoe joint and to each guideline. Paint the bottom few metres white for ease of observation with the ROV when entering the 30” housing.

4.

RIH filling up every joint with seawater.

Note: Use only light oil or solid free grease on the connectors. 5.

Observe the shoe stabbing into the 30” wellhead by ROV or SSTV.


SUBJECT:


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6.

RIH monitoring casing running speeds. Ensure that the speed does not exceed the value previously calculated.

7.

Pick up the 18 3/4” wellhead assembly/running tool assembly. Attach the 20” top cement plug and make up the assembly to the casing string.

8.

Install the hot line to the hydraulic lockdown tool.

9.

Remove the bleeder sub locking plate to prevent pulling a wet string after the cementation.

10. Run the casing string on 5” HWDP (drifted to 2 3/4”). The running string must be filled every joint until landed. When the last joint of the drillpipe running string has been made up, activate the motion compensator to support the weight of the string. Record up and down drag prior to landing. 11. Make up the kelly to the landing string, wash down and land the 18 3/4” wellhead in the 30” wellhead. Apply an overpull of 30,000 lbs to confirm that the 18 3/4” wellhead is fully seated in the 30” wellhead. Set down weight on the wellhead assembly. 12. Activate the hydraulic lockdown mechanism (the mechanical system is preferred, although the hydraulic system may be used instead, via a hot line). Disconnect with the ROV. Confirm lockdown by observing outer sleeve indicator plate downward movement and applying 100,000 lbs overpull to wellhead. Dril-Quip to confirm.

Note: The wellhead locating pins will shear out with 75,000 lbs overpull. 13. Cement the casing to seabed (see Section 3200/SEM). Check for backflow. 14. After cementing set the motion compensator to support the weight of the running string. Rotate the running string 10 turns to the right to release the running tool and open the drain ports on the bleeder sub. 15. Using the motion compensator lift the running tool clear of the wellhead. Be careful that the plug launcher/stinger does not score wellhead sealing area. 16. With the lockdown tool at surface check that the travel of the indicator plate relative to the indicator screw has been a minimum of 2 1/4”. 17. Run rubber-nosed jet sub and jet wellhead/PGB clean. 18. Install the 18 3/4” nominal bore protector before drilling out the casing.

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PREPARATION AND RUNNING 13 3/8" CASING

1.

PREPARATION

1.1

Carry out General Casing Checks as per Sections 2000/GEN and 2900/GEN.

1.2

Change rams and test unless a well specific written instruction is issued by the Drilling Superintendent.

1.3

Recover wear bushing. Ensure any hold-down screws are fully backed out.

1.4

Float shoe and float collar to be 2 joints apart, threadlocked, including the first connection above the float collar.

1.5

If a shut-off baffle is in use, this will normally be located a pup joint above the float collar. All connections up to the first connection above the shut-off baffle to be threadlocked.

1.6

If a stage cementer is in use, connections either end of the cementer to be threadlocked.

1.7

Casing centralisation will be as per Section 2010/GEN unless advised otherwise in the Drilling Programme.

1.8

If a 20” x 13 3/8” casing hanger is used, it will be made up to a 13 3/8” pup joint. Check that the sealing faces of the seal assembly are undamaged. Keep well protected. Check hanger dimensions. Make up hanger to casing hanger running tool and a joint of 13 3/8” casing. Drift the assembly.

1.9

If a slip-type casing hanger is used, select and check 3 joints of casing for ovality and set aside for use across the wellhead.

2.

RUNNING

2.1

Rig up and run 13 3/8” casing as per programme.

2.2

Ensure that the casing is completely filled every joint.

2.3

Monitor mud displacement throughout the run. Avoid high surge pressures caused by running pipe too quickly.

2.4

Observe and record pulling and running weights at regular intervals in open hole.

2.5

Make up the casing hanger assembly, if used, landing joints and circulating head. Break circulation slowly.

2.6

Run casing to shoe depth, circulating at least the last joint in. Take care when hanger is run through the riser and landed off in the casing head spool. Check land-off depth.

2.7

If unable to run casing to depth, due to stuck casing, an emergency slip type hanger will be used. See Wellhead Section.

2.8

Circulate casing. Check for losses throughout circulation, record pressures at various circulating rates. (Minimum circulation volume will be the greater of 120% Annular Volume or 120% Casing Volume.)

2.9

Cement 13 3/8” casing as per Section 3300/GEN. Check for backflow.

2.10

If stage cementing is programmed, cement second stage as per Section 3700/GEN. Check for backflow.

2.11

a)

If a slip-type hanger is in use, drain riser, nipple down 21 1/4” riser. Lift BOP and riser. Install 13 3/8” casing hanger and pack-off as per manufacturer’s procedure and Manual Section relevant to the particular wellhead.

BP EXPLORATION

DRILLING MANUAL SUBJECT: b)

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If an integral type hanger is in use, back out running tool and displace the riser to seawater. Flush hanger area. Drain the riser and recover the landing string. Run jetting tool and jet the pack-off setting area. Ensure fluids are collected into the drain system. Make up and install 13 3/8” packoff as per the manufacturer’s procedure. Set pack-off. Close pipe rams and pressure test the pack-off to the test pressure stipulated in the Drilling Programme.

2.12

Ensure that the casing head spool side outlet is open throughout pressure testing.

2.13

Retrieve running tool.

2.14

Nipple down 21 1/4” BOP’s and riser.

2.15

Cut and dress 13 3/8” casing as required.

2.16

Install and test 13 5/8” wellhead spool as per manufacturer’s procedures and Manual Wellheads Section (Section 5000).

2.17

Nipple up and pressure test 13 5/8” BOP’s as per Section 0420/FIX.

2.18

Install wear bushing.

3.


Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

1 1 1 2 2 1 set 1 1 set 1 4 1 1 1 1 1 1 1

13 3/8” side door elevators. 13 3/8” single joint elevators. 13 3/8” hand slips. 350T 13 3/8” spider elevator slips. 13 3/8” spider slips. BJ Type BB tongs, dressed to 13 3/8”. 13 3/8” plug dropping head. 13 3/8” top and bottom cementing plugs. 13 3/8” circulating swedge c/w 2” lo-torq valve. 13 3/8” Klampon protectors. 13 3/8” power tong. Power unit for tong. 13 3/8” casing drift. Test pump. Travel cutter dressed for 13 3/8” casing if required. Air powered grinder. Plastic injection gun. Plastic packing sticks. 13 3/8” casing as required. Buttress couplings. 13 3/8” cement float shoe. 13 3/8” cement float collar. 13 3/8” dual stage cementing set c/w plugs, if required. 13 3/8” bow spring centralisers. 13 3/8” positive centralisers. 13 3/8” stop rings c/w spiral nails. Centraliser nails. Bakerlok. Casing dope. 13 3/8” landing joint. Slip type casing hanger.

2 1 1 1 1 lot 1 lot 1 lot 1 lot 6 1 drum 1 1

BP EXPLORATION

DRILLING MANUAL SUBJECT: 32 33 34 35 36 37 38

PREPARATION AND RUNNING 13 3/8" CASING 1 lot 1 1 1 1 1 1

Wellhead equipment, as required. Bore protector. Bore protector running tool/combination tool. Test plug. 13 3/8” cup tester c/w spare cup. Stage cementer closing tool, if required. Tam casing circulating packer, if required.

Section

:

2300/FIX

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:

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:

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PREPARATION AND RUNNING 13 3/8" CASING - Dril-Quip SS15 System

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1.

PREPARATION

1.1

Carry out General Casing Checks as per Sections 2000/GEN and 2900/GEN.

1.2

Change pipe rams to casing rams and test unless a well specific written instruction is issued by the Drilling Superintendent.

1.3


1.4

Float shoe and float collar to be at least 2 joints apart, threadlocked, including the first connection above the float collar.

1.5


1.6


1.7


Note: On jack-up wells a positive centraliser should be run close to the wellhead to minimise the risk of the welder accidentally cutting through an inner casing string. 1.8

If a 12 3/4” x 9 5/8” casing hanger is used, it will be made up to a 9 5/8” pup joint. Check that the sealing faces of the seal assembly are undamaged. Keep well protected. Check hanger dimensions. Make up hanger to casing hanger running tool and a joint of 9 5/8” casing. Drift the assembly.

1.9


1.10

If 13 3/8” casing has been omitted, check that the 9 5/8” x 20” centralisers will pass through the MLH prior to running on jack-up wells.

2.

RUNNING

2.1

Rig up and run 9 5/8” casing as per programme.

2.2


2.3

Avoid high surge pressures caused by running too quickly.

2.4

Monitor mud displacement throughout the run.

2.5


2.6

Make up the casing hanger assembly, if used, landing joints and circulating head. Note string weight. Break circulation slowly.

2.7


Note: Do not rotate the casing as this might back out the running tool. 2.8

If unable to run casing to depth, due to stuck casing, an emergency slip-type hanger will be used. See Wellhead Section.

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2.9

Circulate casing. Check for losses throughout circulation. Record pressures at various circulating rates. (Minimum circulation volume will be the greater of 120% Annular Volume or 120% Casing Volume.)

2.10

Cement 9 5/8” casing as per Section 3350/GEN. Check for backflow.

2.11


2.12

a)

If a slip-type hanger is in use, drain riser, nipple down 13 5/8” riser. Lift BOP and riser. Install 9 5/8” casing hanger and pack-off as per manufacturer’s procedure and Manual Section relevant to the particular wellhead.

b)

If an integral type hanger is in use, back out running tool. Open annulus port below the hanger, and wash around the wellhead area. Ensure fluids are collected into the drain system. Make up and install 9 5/8” pack-off as per the manufacturer’s procedure. Set pack-off. Pressure test pack-off as per Wellheads Section.

2.13

Ensure that the 9 5/8” x 13 3/8” annulus is open throughout pressure testing.

2.14

Nipple up and pressure test BOP’s as per Section 0420/FIX.

2.15


3.


Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28

1 1 1 1 2 2 1 set 1 1 set 1 4 1 1 1 1 1 1

9 5/8” side door elevators. 9 5/8” single joint elevators. 9 5/8” casing drift. 9 5/8” hand slips. 350T 9 5/8” spider elevator/slips. 9 5/8” spider slips. BJ Type DB tongs, dressed to 9 5/8”. 9 5/8” plug dropping head. 9 5/8” top and bottom cement plugs. 9 5/8” circulating swedge c/w 2” Lo-torc valve. 9 5/8” Klampon protectors. 9 5/8” power tong. Power unit for tong. Test pump. Travel cutter dressed to 9 5/8”, if required. Air powered grinder. Plastic injection gun. Plastic packing sticks. 9 5/8” casing as required. 9 5/8” casing pup joints. 9 5/8” couplings. 9 5/8” cement float shoe. 9 5/8” cement float collar. Dual stage cementing set c/w plugs, if required. 9 5/8” bow centralisers. 9 5/8” positive centralisers. 9 5/8” stop rings c/w spiral nails. Centraliser nails.

2 2 1 1 2

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DRILLING MANUAL SUBJECT: 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44

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:

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1 1 1 lot 1 1 1 1 1 4 1 1 2 1 lot 1

Bakerlok. Casing dope. 9 5/8” landing joint or MLH/running tool assembly. Slip casing type hanger. Wellhead equipment, as required. Bore protector. Bore protector running tool/combination tool. BOP test plug, complete with spare seals. 9 5/8” cup tester c/w spare cup. Stage cementer closing tool, if required. 9 5/8” x 20” special centralisers (2 x small OD and 2 x large OD - if required). 9 5/8” retrievable packer complete with circulating valve and safety joint. 9 5/8” water bushing (4 1/2” IF box). 9 5/8” wireline set bridge plugs. Cement and chemicals. TAM packer for casing fill-up/circulation.

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1.0

The 9 5/8” casing string is normally set as a production string at total depth (in which case the casing is only run in the event of a well test) or above the objective formation with a 7” liner run to TD in the event of a test.

1.1

Perform all standard checks and procedures as outlined in Sections 2000/GEN and 2900/GEN.

1.2

The string is run with a 2 joint shoe track utilising conventional float equipment. All connections in the shoe track up to and including the first one above the float collar are to be threadlocked.

1.3

The casing hanger is normally sent to the rig made up to an appropriate pup joint to match the casing string. The lock ring is normally removed, but this will be confirmed in the drilling programme.

Note: See Section 5000 for details of wellhead equipment. 1.4

Centralisation Refer to Section 2010/GEN for minimum centralisation scheme.

Note: The string will be centralised according to the formation which has been encountered. For example, if a significant sand body is present in the 12 1/4” hole the 9 5/8” string may be centralised with one springbow per alternate joint to the top of the sand body. This will reduce the possibility of differential sticking while running casing and ensure good stand-off across the sand body when cementing. The programme must always be confirmed prior to running casing. 2.0

EQUIPMENT CHECK LIST General - Single and Dual Stack Systems Casing shoe joints (2 off). Float collar joints (2 off). Casing as required + 10%. Springbow centralisers/stop collars/pins. Rotary casing slips (2 off). Single joint elevator (2 off). Side door elevator (2 off). Slip type elevator (2 off). Slip type spider (2 off). Spare casing collars (2 off). API modified dope. Threadlock. Gyro multishot equipment (if required). Power tong/crew. Klampon protectors (5 off). SSR cement mandrel. Surface cement head with swivel. Top and bottom cement plugs (2 each). Launching ball and dart (2 each). Tam casing circulating packer (if required). Casing spear. Circulating swedge. 9 5/8” retrievable packer complete with storm valve.

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Single Stack System

Item

Dril-Quip Part No.

18 3/4” x 9 5/8” casing hanger with 9 5/8” pup joint installed. 18 3/4” seal assembly. 18 3/4” casing hanger and seal assembly running tool (6 5/8" Reg Box/ 4 1/2” IF Pin).

390004 400000 420028

Dual Stack System

3.0

Item

Dril-Quip Part No.

13 5/8” x 9 5/8” casing hanger with 9 5/8” pup joint installed. 13 5/8” seal assembly. 13 5/8” casing hanger and seal assembly running tool (6 5/8" Reg Box/ 4 1/2” IF Pin).

390019 400003 420079

PREPARATION 1.

Perform the general checks as outlined in Sections 2000/GEN and 2900/GEN.

2.

Prior to running the casing, calculate surge/swab pressures and select an acceptable casing running speed to ensure that the formation breakdown is not exceeded.

3.

Ensure that the landing string is drifted.

4.

Perform the following additional checks: Casing Hanger a)

Inspect the tapered seal area on the upper OD of the hanger to be sure that it is free from damage.

b)

Ensure that the threads of the pup joint made up to the casing hanger are compatible with the threads of the casing string.

c)

Inspect the 3 anti-rotation slots in the top ID for damage.

d)

Inspect the full bore tool/tieback threads in the top ID of the hanger for damage.

e)

Inspect the 2 running tool lock ring grooves in the ID of the hanger for damage.

f)

Inspect the running tool seal area, located below the lock ring grooves, for damage.

Seal Assembly g)

Inspect the two metal seal lips on the seal assembly OD and ID for damage.

h)

Check that the seal assembly outer lock ring is removed.

i)

Inspect the retrieval profile on the top ID of the locking sleeve.

j)

Ensure that the 8 grooved shear pins are correctly installed above the outer lock ring. These pins prevent premature activation of the locking sleeve and have a combined shear value of 9,920 lbs.

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k)

Inspect the running profile and wear bushing locking profile on the ID of the assembly for damage.

l)

Check that the two lead impression pins located in the ID of the seal assembly extend 1/8” beyond the shoulder where they are installed. These pins provide a positive indication of seal location relative to the hanger in the event the seal assembly does not lock down.

m) Inspect the inner lock-down ring (that locks the seal assembly to the casing hanger) for correct installation and that it is free from damage. The ring should be free to rotate. Casing Hanger Seal Assembly Running Tool

5.

n)

Ensure that the actuator sleeve/inner body strokes open and closed. Full travel of the tool is 11 1/4” for the 18 3/4” running tool and 11” for the 13 5/8” running tool.

o)

Inspect the condition of the “O” ring and polypack seals on the bottom of the running tool body.

p)

Confirm that the split lock ring is retracted and that its OD is no greater than the OD of the body seal area.

q)

Ensure that the cap screws in the anti-rotation keys are tight.

r)

Ensure that the 8 shear pins on the inner body are correctly installed.

s)

Ensure that the cap screws on top of the running tool are tight.

Whenever possible efforts should be made to make up the running tool, seal assembly, casing hanger and plug launching mechanism prior to running the casing string. The assembly will normally be made up in the rotary table and laid down on the pipe rack ready for use. Making Up the Assembly a)

Pick up the running tool and make up the crossover for the SSR cementing wiper plugs. Do not install the plugs at this stage. Stand the assembly back in the derrick.

b)

Pick up the 9 5/8” casing hanger and pup joint and set it in the RT.

c)

Lower the running tool into the casing hanger while aligning the anti-rotation keys into their slots in the hanger. Allow the running tool to stroke closed and put the full weight of the drill pipe on the running tool. Pick up and stroke the running tool open, but do not lift the main body out of the casing hanger.

d)

Insert the torque bars into the torque bar holes of the running tool and rotate the running tool to the right until no more movement is possible. Excessive force is not required.

e)

Rotate the running tool a minimum of 5 1/2 to 6 turns to the left until a positive torque build-up is felt. This moves the actuator sleeve down behind the split lock ring and locks the running tool to the casing hanger.

f)

Slack off all the drill pipe weight. The running tool strokes in approximately 5 cm and stops. Pick back up on the running tool until it strokes out fully (5 cm). Rotate the running tool to the right 3 turns. Remove the torque bars from the running tool and lift the running tool from the casing hanger.

g)

Lift the seal assembly onto the running tool until the shear pins on the running tool snap into a mating groove on the ID of the seal assembly. Ensure that the seal assembly is properly snapped over the 8 shear pins of the running tool. The seal assembly should rotate freely.

h)

Install the cement wiper plugs on the bottom of the running tool.

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i)

Lower the running tool assembly into the casing hanger aligning the anti-rotation keys with the matching slots in the casing hanger. Set the entire weight of the running tool and drill pipe on the hanger.

j)

Re-install the torque bars. Rotate the running tool 3 turns to the left relocking the running tool to the casing hanger. Turn the running tool back to the right 1/8th of a turn (do not exceed 1/4 of a turn). To check that the running tool is correctly made up observe the body of the running tool through the gap between the bottom of the seal assembly and the top of the casing hanger. A knurled band should be visible and centred (+/- 1/4”) within the gap.

k)

Lay down the running tool, casing hanger, seal assembly and wiper plugs on the pipe rack ready for use or rack back in the derrick.

4.0

RUNNING THE CASING

4.1

It is normal practice to make a wiper trip prior to running 9 5/8” casing. Confirm the section TD (with logging depth) and ensure a minimum 5m pocket below the planned shoe depth (unless otherwise instructed).

4.2

Ensure that mud properties are suitable for running casing, conditioning if required (if not already carried out).

4.3

Retrieve the Nominal Bore Protector from the wellhead. If the BOP stack has a flex joint with a restrictive wear bushing installed retrieve that wear bushing.

4.4

Run the shoe track, check the float equipment for obstruction and correct operation.

Note: The shoe track connections should be Bakerlocked. 4.5

Run the casing filling it with mud. Draw a graph of casing joints run versus hookload and use this to check that the casing is being filled correctly. Circulate at the 13 3/8” shoe while changing over to slip type elevator/spider.

4.6

Install the casing hanger/running tool assembly on the casing string. Ensure that the hook on the travelling block is unlocked at this point and that it remains unlocked until the casing hanger has landed.

4.7

Activate the motion compensator and adjust it to support the weight of the running string only. Run the landing string to +/- 25m above the wellhead. Be prepared to wash down the last few joints if necessary. Note the up and down drag weights.

4.8

Ensure that the kill and choke lines are open to atmosphere prior to running the casing hanger through the BOP to avoid pressure surges damaging the pack-off seal.

4.9

Land the 9 5/8” casing hanger in the wellhead. Slack off all of the casing string weight. Allow the compensator to stroke to the mid-point position and verify the landing string/casing hanger elevation.

4.10

Circulate bottoms up + 20% or 120% casing volume (whichever is greater) noting circulating pressure/rates for both pumps. Cement the casing as in Section 3350/GEN. If the plugs bump test the casing to 3500 psi*. Note: Do not pick up or attempt to rotate the casing string during circulating, cementing or displacing.

4.11

At the conclusion of the cementing operation and after removing the cement lines from the running string, adjust the motion compensator to put a minimum weight of 15,000 lbs down on the casing hanger seal assembly running tool. Rotate the running string to the right 5 to 6 turns or until the running string drops +/- 25 cm. Do not rotate the running string past this point. Adjust the motion compensator

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to put the entire running string weight on the running tool. This weight further energises the seal assembly. 4.12

With the running string and choke (kill) line open, close the pipe rams and test the seal assembly to 5000 psi* through the kill (choke) line.

4.13

The test on the seal assembly must be done with the cement unit and the volumes pumped observed. Avoid applying pressure to the casing annulus if the pack-off is leaking by calculating the required fluid volume to obtain the test. If problems are encountered testing the seal assembly, consult Table 1, page 6.

4.14

After testing the seal assembly pick straight up to recover the running tool. Apply a minimum overpull of 60,000 lbs to shear the pins on the running tool, releasing the running tool from the locked down seal assembly. POOH without rotating the string.

4.15

Test the BOP stack as per the procedure in Section 0420/SEM. If drilling is to continue below the 9 5/8” shoe, install the bore protector.

* NOTE: THESE PRESSURES MAY BE VARIED.

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PREPARATION AND RUNNING 9 5/8" CASING - Dril-Quip SS15 System TABLE 1

SEAL ASSEMBLY TEST TROUBLESHOOTING CHART Symptoms

Possible Problem

Suggested Solution

Fluid loss at test pump unit.

Test pump unit.

• Repair leak in test pump unit and test again.

Fluid returns in the wellbore.

Test rams.

• Open and close test rams and test again. • Select new test rams and test again.

Fluid returns at the choke/ kill manifold.

• Valve in the choke/kill manifold.

• Open and close valves and test again.

• Choke/kill valves at the BOP.

• Open and close valves and test again. • Close back-up choke/kill valves at the BOP and test again.

Continuous fluid returns through the drill pipe running string.

Test seals on the Casing Hanger Running Tool.

• Retrieve Running Tool and Seal Assembly and rerun Seal Assembly Running Tool with Seal Assembly and test again.

Fluid noticed through the camera between the wellhead and wellhead connector.

Wellhead ring gasket.

• Replace wellhead ring gasket and test again.

Fluid noticed through the camera from the main BOP.

Ram body/wellhead connections.

• Retrieve stack, replace ring gasket(s), rerun BOP and test again.

Fluid noticed through the camera from the test line connections.

Packing in choke/kill test line.

• Retrieve riser, replace packing, rerun riser and test again.

No visible fluid loss.

Seal assembly.

• Check weight on Running Tool (must be 15,000 lbs minimum). • Pull Running Tool and Seal Assembly, run Mill and Flush Tool, run a new Seal Assembly Running Tool and perform the test again.

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PREPARATION AND RUNNING 7" CASING

1.

PREPARATION

1.1

Carry out General Casing Checks as per Section 2000/GEN and 2900/GEN.

1.2

Change pipe rams to casing rams and test unless a well specific written instruction is issued by the Drilling Superintendent.

1.3


1.4

Float shoe and float collar to be 2 joints apart, threadlocked, including the first connection above the float collar

1.5


1.6


1.7


1.8

If a 12 3/4” x 7” casing hanger is used, it will be made up to a 9 5/8” pup joint. Check that the sealing faces of the seal assembly are undamaged. Keep well protected. Check hanger dimensions. Make up hanger to casing hanger running tool and a joint of 7” casing. Drift the assembly.

1.9


2.

RUNNING

2.1

Rig up and run 7” casing as per programme.

2.2


2.3

Avoid high surge pressures caused by running too quickly.

2.4

Monitor mud displacement throughout the run.

2.5


2.6

Make up the casing hanger assembly, if used, landing joints and circulating head. Break circulation slowly.

2.7


2.8

If unable to run casing to depth, due to stuck casing, an emergency slip- type hanger will be used.

2.9

Circulate casing. Check for losses throughout circulation. Record pressures at various circulating rates. (Minimum circulation volume will be the greater of 120% Annular Volume or 120% Casing Volume.) Ensure Corrosion Inhibitor is added to all mud that will remain in the 7” x 9 5/8” Annulus ahead of the cement.

2.10

Cement 7” casing as per Section 3400/GEN. Check for backflow.

2.11


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PREPARATION AND RUNNING 7" CASING

a)

If a slip-type hanger is in use, drain riser, nipple down 13 5/8” riser. Lift BOP and riser. Install 7” casing hanger and pack-off as per manufacturer’s procedure and Manual Section relevant to the particular wellhead.

b)

If an integral type hanger is in use, back out the running tool. Open annulus port below the hanger, and wash around the wellhead area. Ensure fluids are collected into the drain system. Make up and install 7” pack-off as per the manufacturer’s procedure. Set pack-off. Pressure test pack-off as per Wellheads Section.

2.13

Ensure that the 7” x 9 5/8” annulus is open throughout pressure testing.

2.14

Nipple up and pressure test BOP’s as per Section 0420/FIX.

2.15


NOTE In the event that Mudline Suspension Equipment is in use, then a Well Specific Programme will be issued. 3.


Item

Quantity

Description

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32

1 1 1 1 2 2 1 set 1 1 set 1 4 1 1 1 1 1 1

7” side door elevators. 7” single joint elevators. 7” casing drift. 7” hand slips. 350T 7” spider elevator/slips. 7” spider slips. BJ Type DB tongs, dressed to 7”. 7” plug dropping head. 7” top and bottom cement plugs. 7” circulating swedge c/w 2” Lo-torc valve. 7” Klampon protectors. 7” power tong. Power unit for tong. Test pump. Travel cutter dressed to 7”, if required. Air powered grinder. Plastic injection gun. Plastic packing sticks. 7” casing as required. 7” casing pup joints. Radioactive marker, if required. 7” couplings. 7” cement float shoe. 7” cement float collar. Dual stage cementing set c/w plugs, if required. 7” bow centralisers. 7” positive centralisers. 7” stop rings c/w spiral nails. Centraliser nails. Bakerlok. Casing dope. 7” landing joint.

2 2 1 1 2

1

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DRILLING MANUAL SUBJECT: 33 34 35 36 37 38 39 40

PREPARATION AND RUNNING 7" CASING 1 1 lot 1 1 1 1 1 1

Slip casing type hanger. Wellhead equipment, as required. Bore protector. Bore protector running tool/combination tool. Test plug. 7” cup tester c/w spare cup. Stage cementer closing tool, if required. Tam casing circulating packer, if required.

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PREPARATION AND RUNNING 7" BAKER (BROWN) HMC LINER

Hanger Loading Forces Determine the maximum loading possible on the casing during the hanger setting procedure. Take into account the following forces, which will be accumulative: a) b) c) d)

Liner hanging weight. Internal pressure to initially set the hanger and shear the ball seat. Pressure to bump plug (if greater than b)). Running string set-down weight prior to cementing (if required and stated in the programme).

If calculations indicate loadings are within 15 percent of casing design loads, alternative hanger designs may have to be considered. It is highly unlikely that single cone hanger equipment will satisfy casing loading criteria. Multi cone equipment should be the first choice when selecting hanger equipment. 1.2

An Isolation Packer may or may not be used in conjunction with the 7” liner. This will be advised in the Drilling Programme.

1.3

On exploration wells the 7” liner will normally form a production string with 9 5/8” casing and will usually only be run in the event of a well test. In some high pressure applications, it may be necessary to tie back the liner to the wellhead.

1.4

When 7” casing is onboard complete all general casing checks as per Sections 2000/GEN and 2900/GEN.

1.5

If a casing test is required prior to running the liner, run a positrieve packer to +/- 50m above the 9 5/8” shoe. Test the 9 5/8” integrity by pressuring the 5” x 9 5/8” annulus to casing test pressure as outlined in the programme. The drilling office will confirm if test is required.

1.6

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe to confirm DP tally. The DP running string must be drifted to a minimum of 2 1/2” (the OD of the metal body of the pump-down plug) on the way out of the hole on the pre-liner check trip. If the pipe is not drifted when POH then it must be drifted when running the liner.

1.7

Ensure that the dart sub is laid out on the last trip out of the hole.

2.


2.1

Baker (Brown) HMC Liner Hanger Equipment 1.

7” x 9 5/8” liner hanger assembly comprising: 7” LS sleeve with PBR extension. Profile nipple with RPSA profile. HMC hanger. Length of PBR to be 6 ft for vertical wells and 15 ft for deep or deviated wells.

2.

Liner hanger running tool assembly comprising: CS setting tool with RS pack-off assembly or inverted swab cup assembly. Upper slick tail pipe assembly (2 7/8” EUE Pin - 2 7/8” Hydril CS pin). Lower tail pipe assembly with swivel and type 1 liner wiper plug.

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Note: It is normal for two complete assemblies of items 1 and 2 to be assembled and tested by the supplier and to be shipped to the rig in protective cradles. 3.

Plug dropping cement head and heavy duty swivel or top drive liner cementing system (see Figure 1): Flag sub (4 1/2” IF). Lift nipple (4 1/2” IF). 2 Nos. Float collars with baffle plate. 2 Nos. Type 2 landing collar with shear-out sleeve. 2 Nos. Type V set shoe. 2 Nos. Drill pipe pump down plug. 2 Nos. 1 3/4” setting ball.

}

Connections to match casing.

Notes: a) The liner hanger utilises VAM connections throughout. b) Pup joints and a radio-active marker may be required. c) If a standard float collar is supplied by BP, then a catcher sub will be required. 4. 2.2

Cement Kelly and drive bushings.

Liner Handling Equipment 2 Nos. 7” side door elevators. 2 Nos. 7” single joint elevators c/w swivel sling. 2 Nos. 7” rotary hand slips. (If non-upset casing is run then YC elevators and spider are required.) 4 Nos. 7” klampon protectors. 2 Nos. Power tong dressed for 7” casing. 2 Nos. Hydraulic power unit for above. 2 Nos. Torque - turn units (if required). 6 Nos. Spare casing collars. 1 No. 7” casing spear c/w grapple/pack-off and stop ring. (Specify weight.) 7” springbow centralisers (as required). 7” stop collars (2 per centraliser). 1 No. 7” casing drift. API modified dope. Threadlock.

3.

PREPARATION Check and inspect the assemblies for the following: 1.

Weight and grade of hanger.

2.

Dimension and part numbers of assemblies conform to those as per Figure 2 on page 8 of this procedure. Measure all lengths, OD’s and ID’s.

3.

PBR size and pressure rating.

Note: On occasions a longer PBR may be supplied. 4.

Hanger pins: 2 Nos. 3/8” pins (giving shear rating 1166 psi).

5.

Shear pins in ball seat of landing collar - 5 Nos. 1/2” pins (shear rating 2500 psi).

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6.

Ensure left hand thread on floating nut is properly engaged inside setting sleeve. Mark the tool and sleeve extension with paint to show if tool begins to back off at any time prior to running.

7.

Make up slick tailpipe and check for damage at sealing area. Check swivel on tailpipe.

8.

Type 1 liner wiper plug is used. Check compatibility of the liner wiper plug with the weight of the 7” casing.

9.

Size and number of Type 1 liner wiper plug shear pins. This information should be available in the documentation with an estimated shear pressure (normally 6 Nos. 3/8” giving shear pressure +/600 psi).

10. Free passage of setting ball through the assembly including the Type 1 wiper plug. 11. Seating of the setting ball in the landing collar and shear-out sleeve. 12. Bore of PBR is compatible with outside diameter of compression set packer seal stem. 13. Free passage of pump down dart and setting ball through all tools, i.e. kelly cocks, bumper subs, crossover subs, drillpipe, etc.

Note: On semi-submersible units the use of the cementing kelly eliminates the use of bumper subs under normal weather conditions. However, 2 bumper subs with 60” stroke may be required in adverse weather conditions. The minimum drift of the bumper subs is 2 1/2” for 7” liners and 2” for 5” and 4 1/2” liners. Ensure passage of the ball and dart through the bumper subs. 14. Pressure test plug dropping head and flag sub assembly against kelly cock to the casing test pressure. 15. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the “V” shoe and float collar. 16. Check the condition and rating of the cement manifold swivel to confirm that it is heavy duty. 17. Prior to running the liner, install the pump down dart in the cement manifold and torque the lift sub to 12,000 ft/lbs. Mark the body and lift sub with white paint to indicate backing out. Make up the cement manifold to the cement kelly and lay out the assembly on the pipe rack. 18. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. 19. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded. 4.

RUNNING THE LINER 1.

Run the liner assembly as per Figure 2 on page 8 of this Section. The shoe track is to consist of the following: Side Exit Shoe. 2 joints of 7” casing. Float collar with baffle plate. 1 joint 7” casing. 1 joint of casing. Type 2 landing collar with shear out seat.

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Notes: a) If drilling out of liner shoe is programmed, a side exit shoe with bakelite internals to be used. b) All connections including casing collars to one joint above the landing collar to be threadlocked. 2.

The required setting depth of the landing collar should be checked with the drilling office prior to the pre-liner clean-out trip. This will depend on the lowermost test/completion interval and the required sump below this for logging (usually 20m). This may have to be extended if TCP guns are required to be dropped into the sump.

3.

Liner lap will be 150m unless otherwise specified.

4.

One or more casing pup joints will normally be positioned in the string at depths to be specified by the drilling office. Also a radioactive collar may be positioned above the objective.

5.

Liner length to be such that when set ± 2m off bottom, the top of the tie-back packer will be a minimum of ± 1m below the nearest casing collar.

6.

Centraliser programme to be confirmed by drilling office (refer also to Section 2010/GEN).

Notes: a) Centralisers should never be positioned across a collar or stop collar on a liner. b) Gauge the centralisers prior to running. 7.

Make up the shoe track and check the float equipment.

Note: Bakerlok all connections on the first 4 joints. 8.

Run the liner filling every joint.

Notes: a) Use the stabbing guide. b) Install pup joints and radio-active markers as indicated in the drilling programme. c) If a radio-active marker is installed, ensure that it is only handled by service company personnel. 9.

Make up hanger/setting tool assembly. Ensure no rotation of tool and setting sleeve. Do not apply torque across the hanger assembly, i.e. tong only on hanger bottom or top subs.

Note: a) Start threads using a chain tong. b) Leaving the slips on the liner joint, pick up 1m to check that the connection is correctly made up. 10. Circulate through the completed liner assembly. Pressure is not to exceed 800 psi. Visually check hanger for leaks and record pressures at various circulation rates. 11. Note weight of full liner on Martin Decker. 12. RIH on 5” DP (do not use HWDP). Ensure the first 15 stands of pipe have protectors removed (to reduce the chance of cementing up the string and to allow the facility to washover if required). RIH filling every stand. Drift every stand to 2 1/2” minimum. Use the drill pipe wiper rubber and ensure string does not turn in table.

Note: a) Do not exceed the calculated running speed. b) Always use a back-up tong when running the complete liner assembly.

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13. Check up and down drags at the 9 5/8” casing shoe. 14. Continue RIH. Pick up cement kelly/plug holder/kelly cock. Ensure running string is spaced out such that with the liner shoe 2m off bottom, the kelly is at mid point, thus allowing enough overstand to set on bottom if necessary.

Note: Wash and work pipe through any tight spots but beware of packing off the annulus which may prematurely set the hanger. (If the differential pressure inside the liner is greater than 1200 psi, the hanger may be set.) 15. Check string weight and up/down drags. 16. Lock the elevators and install the plug holder with kelly cock below. Wash down (with the compensator open on floating units). Do not exceed 600 psi. Rig up cementing lines and test to 5000 psi against the kelly cock.

Note: Use sufficient chiksan swings to allow for pick-up clear of the PBR. 17. Break circulation slowly. Tag bottom with liner, mark the pipe and pull back 2m. Circulate bottoms up + 20% or 120% string volume whichever is greater. Increase the circulation rate but do not exceed 1000 psi surface pressure. In high temperature wells extended circulation may be required. 18. Check string weight up and down, with and without circulation. To prevent packing off, do not move the liner without circulating.

Note: a) Do not slack off more than 80% of the liner weight. b) Do not exceed the maximum ECD achieved when drilling the 8 1/2” hole. 5.

SETTING PROCEDURE 1.

Drop the setting ball through the 3” bull plug in the plug launching head or pull back and break out the kelly if hole conditions allow. Allow time for the ball to seat in the landing collar/shear-out sub. The setting ball may be pumped down at a flowrate of 3 bbl/min. Limit pressure to 1000 psi.

Note: While pumping the ball down, check the pick-up and slack-off weights, tag bottom and pick up to the liner setting depth, i.e. full-up stroke weight (total stroke of running tool is 1.5m). 2.

When the ball lands, pressure up in 500 psi stages to 1600 psi to set the hanger. (Setting pressure should be 1200 - 1400 psi.) Hold pressure for 10 minutes.

Note: If 1600 psi does not set the hanger, pick up and increase the pressure in 200 psi increments, checking for a set after each increase. 3.

Check that the hanger has properly activated by slacking off 30 - 40,000 lbs. Liner weight should be lost before the shoe reaches bottom. a)

If hanger has set, shear ball from the shear sub, with a pressure of +/- 1,800 psi.

b)

If hanger has not set, sit liner on bottom and shear ball from the shear sub.

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4.

Establish circulation and circulate at various rates (i.e. 50, 100, 150, 250, 300, 350 and 400 gpm) and record surface pressures. Check for losses. If losses are observed, it may be necessary to restrict the cement displacement rate.

5.

Pick up to 15,000 lbs less than the theoretical neutral running string weight. Rotate the running string 10 turns to the right. The hanger should release after 6 turns.

6.

Pick up the running string weight plus 0.5m to ensure that the tool is released.

Note: a) Pick-up must be less than the length of the tailpipe which extends below the hanger. b) When using an RS pack-off, the running tool cannot be re-engaged. 7.

Prior to cementing, set down 10,000/15,000 lbs weight on the hanger if the RS pack-off assembly is being used. If the inverted cup type setting tool is being used, 40,000/50,000 lbs above plug bump pressures must be set down on the hanger.

8.

Break circulation and cement as per Section 3450/GEN.

Note: Do not exceed the maximum ECD achieved during drilling the 8 1/2” hole. 9.

After checking for backflow, then POOH quickly to 500m above the top of the liner hanger.

Note: If there are indications of cement inside the string, e.g. the string is pulling wet, then pump a slug to clear the string. 10. Continue POOH. Ensure hole is kept full. Monitor fill volume. If string is still pulling wet, then circulate clean conventionally.

Note: Do not spin the table when breaking out connections. POOH as this can cause part of the running string to be left downhole. 11. Refer to Section 3450/GEN for details of the liner clean-out operation.

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PREPARATION AND RUNNING 7" BAKER (BROWN) HMC LINER FIGURE 1 TOP DRIVE CONNECTION

BAILS

5" DRILL PIPE PUP JOINT 4 1/2" IF BOX x PIN 10-15FT LONG

ELEVATOR

5" DRILL PIPE PUMP DOWN PLUG KELLY VALVE TO HOLD PUMP DOWN PLUG. 4 1/2" IF BOX x PIN

SETTING BALL

3" WECO CONNECTION

KELLY VALVE TO HOLD SETTING BALL

TOP DRIVE LINER CEMENTING SWIVEL. 3" ID WITH 3" 1502 WECO INLET. 4 1/2" IF BOX x PIN, 3" ID TENSILE LOAD RATING: - 1,000,000 LBS PRESSURE RATING: - 15,000 PSI TEST - 10,000 PSI WORKING PRESSURE 3" WECO CONNECTION

2 7/8" OD TORQUE TUBE BETWEEN GUIDE RAILS 90° BEND OPTIONAL

SAFETY LINE/CHAIN

3" M x 2" F WECO 1502 ADAPTOR

2" x 2" 1502 LOW TORQUE VALVE

FLAG INDICATOR SUB.. 4 1/2" IF BOX x PIN

911208/15

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SUBJECT: PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER 1.1



If calculations indicate loadings are within 15 percent of casing design loads, alternative hanger designs may have to be considered. It is possible that single cone hanger equipment will satisfy casing loading criteria. Multi cone equipment should be the first choice when selecting hanger equipment.

Note: The HSR hanger is a single line hanger. 1.2


1.3


1.4

When 7” casing is onboard, complete all general casing checks as per Sections 2000/GEN and 2900/GEN.

1.5


1.6

On the last trip out of the hole, conduct a flow check and record torque readings with the bit on bottom and just off bottom at 10, 15 and 20 RPM. Repeat this with the BHA positioned at the same depth as the hanger (cased hole torque).

Note: The maximum allowable surface torque is 80% of this value. 1.7

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe while POH to confirm DP tally. The liner running string must be drifted to a minimum of the OD of the metal body of the pump-down plug. A wireline retrievable dart/survey tool may be dropped as a drift. If the pipe is not drifted when POH, then it must be drifted when running the liner.

1.8


2.


2.1

Baker (Brown) Rotating Liner Hanger Equipment 1.

7” x 9 5/8” HSR rotating liner hanger assembly comprising: 7” LS sleeve with PBR extension. Profile nipple with RS profile. HSR rotating hanger.

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SUBJECT: PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER Length of PBR to be 6 ft for vertical wells and 15 ft for deep or deviated wells. 2.

Rotating liner hanger running tool assembly comprising: Shear-out junk bonnet assembly. 2 RH rotating setting tool with retrievable or drillable pack-off bushing. Slick tailpipe assembly with swivel and type 1 liner wiper plug.

Note: It is normal for two complete assemblies of items 1 and 2 to be assembled and tested by the supplier and shipped to the rig in protective cradles. 3.

Plug dropping cement head and heavy duty swivel or top drive liner cementing system (see Figure 1): Flag sub (4 1/2” IF). Lift nipple (4 1/2” IF). 2 Nos. Float collar with baffle plate. 2 Nos. Type 2 landing collar with shear-out sleeve. 2 Nos. Type V set or side exit shoe. 2 Nos. Drill pipe pump down plug. 2 Nos. 1 3/4” setting ball.

}


Note: a) The liner hanger utilises VAM connections throughout. b) Pup joints and a radio-active marker may be required. c) If standard float collar is supplied by BP, then a catcher sub will be required. 4. 2.2



3.



2.

Dimensions and part numbers of assemblies conform to those as per Figure 2 on Page 8 of this procedure. Measure all lengths, OD’s and ID’s.

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SUBJECT: PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER 3.



Hanger pins: 2 Nos. 3/8” pins (shear rating 1166 psi).

5.


6.


7.


8.


9.


10. Free passage of setting ball through the assembly including the Type 1 wiper plug. 11. Seating of the setting ball in the landing collar shear out sleeve. 12. Bore of PBR is compatible with outside diameter of compression set packer seal stem. 13. Free passage of pump down dart and setting ball through all tools, i.e. kelly cocks, bumper subs, crossover subs, drillpipe, etc.

Note: On semi-submersible units the use of the cementing kelly eliminates the use of bumper subs under normal weather conditions. However, 2 bumper subs with 60” stroke may be required in adverse weather conditions. The minimum drift of the bumper subs is 2 1/2” for 7” liners and 2” for 5” and 4 1/2” liners. Ensure passage of the ball and dart through the bumper subs. 14. Pressure test plug dropping head and flag sub assembly against kelly cock to 5000 psi. 15. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the “V” shoe and float collar. 16. Check the condition and rating of the cement manifold swivel to confirm that it is heavy duty. 17. Prior to running the liner, install the pump down dart in the cement manifold and torque the lift sub to 12,000 ft/lbs. Mark the body and lift sub with white paint to indicate backing out. Make up the cement manifold to the cement kelly and lay out the assembly on the pipe rack. 18. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. 19. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded. 4.


Run the liner assembly as per Figure 2 on page 8 of this section. The shoe track is to consist of the following:

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SUBJECT: PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER Side Exit Shoe. 2 joints of 7” casing. Float collar with baffle plate. 1 joint 7” casing. 1 joint of casing. Type 2 landing collar with shear-out seat.

Notes: a) If drilling out of liner shoe is programmed, a side exit shoe with bakelite internals to be used. b) All connections including casing collars to one joint above the landing collar to be threadlocked. 2.

The required setting depth of the landing collar should be checked with the drilling office prior to the pre-liner clean-out trip. This will depend on the lowermost test/completion interval and the required sump below this for logging (usually 20m). This may have to be extended if TCP guns are required to be dropped into sump.

3.


4.


5.

Liner length to be such that when set ± 2m off bottom the top of the tie-back packer will be a minimum of ± 1m below the nearest casing collar.

6.


Note: a) Centralisers should never be positioned across a collar or stop collar on a liner. b) Gauge the centralisers prior to running. 7.




Notes: a) Use the stabbing guide. b) Install pup joints and radio-active marker as indicated in the drilling programme. c) If a radio-active marker is installed, ensure that it is only handled by service company personnel. 9.

Make up hanger/setting tool assembly. Ensure no rotation of tool and setting sleeve. Do not apply torque across the hanger assembly, i.e. tong only on hanger bottom or top subs.

Notes: a) Start threads using a chain tong. b) Leaving the slips on the liner joint, pick up 1m to check that the connection is correctly made up. 10. Circulate through the completed liner assembly. Pressure is not to exceed 700 psi. Visually check hanger for leaks and record pressures at various circulation rates. 11. Note weight of full liner on Martin Decker. 12. Check hanger for any damage to casing collar. Check the 4 x 3/8” shear pins on the split junk bonnet. Lower hanger assembly through rotary and set DP slips on the 5” lift nipple - do not set

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SUBJECT: PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER slips on the setting sleeve. Be careful to keep the hanger centred while lowering through the table to avoid damage to the piston, slips, etc. 13. RIH on 5” DP (do not use HWDP). Ensure the first 15 stands of pipe have protectors removed (to reduce the chance of cementing up the string and to allow the facility to washover if required). RIH filling every stand. Drift every stand to 2 1/2” minimum. Use the drillpipe wiper rubber and ensure string does not turn in the table.

Notes: a) Do not exceed calculated running speed. b) Always use a back-up tong when running the complete liner assembly. 14. Check up and down drags at the 9 5/8” casing shoe. 15. Continue RIH. Pick up cement kelly/plug holder/kelly cock. Ensure running string is spaced out such that with the liner shoe 2m off bottom, the kelly is at mid point, thus allowing enough overstand to set on bottom if necessary.

Note: The 2RH Running Tool and HR Hydraulic Rotating Liner Hanger assembly allow the liner to be rotated while washing down through bridges in open hole as long as the 4 x 3/8” brass shear pins in the split junk bonnet in the PBR top remain intact (Baker do not recommend this). The shear screws are sheared out only if the liner weight is lost and 12,400 lbs force is applied to the liner top. This could occur either if a) the entire weight of the liner is lost due to a bridge whilst washing down, or b) by catching an upset on the hanger assembly (slips, cylinder, etc.) on the BOP stack, wellhead or other obstruction. To prevent shearing the pins, beware when running the liner assembly through the BOP and wellhead and limit slack-off weight when washing down through bridges to 80% of the liner weight. If the junk bonnet pins are sheared prematurely, rotation should not be applied until the hanger has been set. 16. Check string weight and up/down drags. 17. Lock the elevators and install the plug holder with kelly cock below. Wash down (with the compensator open on floating units) rotating only if necessary. Do not exceed 600 psi. Rig up cementing lines and test to 5000 psi against the kelly cock.

Note: Use sufficient Chiksan swings to allow for pick-up clear of the PBR. 18. Break circulation slowly. Tag bottom with liner, mark the pipe and pull back 2m. Circulate bottoms up + 20% or 120% string volume whichever is the greater. Increase the circulation rate, but do not exceed 1000 psi surface pressure. In high temperature wells, extended circulation may be required. 19. Check string weight up and down, with and without circulation. To prevent packing off, do not move the liner without circulating.



Drop the setting ball through the 3” bull plug in the plug launching head or pull back and break out the kelly if hole conditions allow. Allow time for the ball to seat in the landing collar/shear out sub.

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SUBJECT: PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER Setting ball may be pumped down at a flowrate of 3 bbl/min. Limit pressure to 1000 psi.

Note: While pumping the ball down, check the pick-up and slack-off weights, tag bottom and pick up the liner to setting depth, i.e. full-up stroke weight (total stroke of running tool is 1.5m). 2.

When the ball lands pressure up in stages and set the hanger, setting pressure should be 1600 psi. Hold pressure for 10 minutes.

3.

Check hanger has set by slacking off running string. Liner weight should be lost before shoe reaches bottom. If 1600 psi does not set the hanger, pick up and increase pressure in 200 psi increments, checking for a set after each increase. a)

When hanger has set, set down +/- 30000 lbs DP weight, mark the pipe and shear ball and seat at a pressure of +/- 2700 psi.

b)

If hanger has not set, sit the liner on bottom and shear ball and seat.

4.

Establish circulation and circulate at various rates (i.e. 50, 100, 150, 250, 300, 350 and 400 gpm) and record surface pressures. Check for losses. If losses are observed it may be necessary to restrict the cement displacement rate.

5.

Pick up to 15,000 lbs less than the theoretical running string weight. Rotate the running string 10 turns to the right. The hanger should release after 6 turns.

6.

Pick up the running string weight plus 0.5m to ensure that the tool is released.

Notes: a) Pick-up must be less than the length of the tailpipe which extends below the hanger. b) When using an RS pack-off, the running tool cannot be re-engaged. 7.

Prior to cementing, set down 10,000/15,000 lbs weight on the hanger if the RS pack-off assembly is being used. If the inverted cup type setting tool is being used, 40,000/50,000 lbs above plug bump pressures must be set down on the hanger.

8.

Break circulation and commence right hand rotation. 4-5 turns will transmit torque to the liner. Limit torque total to (cased hole torque + liner thread torque) x 80%. Establish rotation of liner at 15-20 rpm. Only rotate the liner when circulating.


Cement the liner as per Section 3450/GEN.

10. After checking for backflow, then POOH quickly to 500m above the top of the liner hanger.



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SUBJECT: PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER FIGURE 1 TOP DRIVE CONNECTION

BAILS


ELEVATOR


SETTING BALL

3" WECO CONNECTION




SAFETY LINE/CHAIN




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SUBJECT: PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER

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PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER HANGER WITH CPH PACKER



If calculations indicate loadings are within 15 percent of casing design loads, alternative hanger designs may have to be considered. It is possible that single cone hanger equipment will not satisfy casing loading criteria. Multi cone equipment should be the first choice when selecting hanger equipment.

Note: The HSR hanger is a single cone hanger. 1.2

The CPH packer is run to avoid sole reliance on the cement in the liner lap. It is weight set and gives the advantage that the cement above the lap can be circulated out immediately that the cement job is completed. The preferred option is to run an integral packer with the liner.

1.3


1.4


1.5


1.6


1.7

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe while POH to confirm DP tally. The liner running string must be drifted to a minimum of 2 1/2” (the OD of the metal body of the pump-down plug). A wireline retrievable dart/survey tool may be dropped as a drift. If the pipe is not drifted when POH, then it must be drifted when running the liner.

1.8


2.


2.1

Baker (Brown) HSR Liner Hanger with CPH Packer 1.

7” x 9 5/8” liner hanger assembly comprising: CPH liner packer, RH type with PBR. HSR rotating liner hanger. Length of PBR to be 6 ft for vertical wells and 15 ft for deep or deviated wells.

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PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER HANGER WITH CPH PACKER Liner hanger running tool assembly comprising: Shear-down junk bonnet. 2RH setting tool with retrievable pack-off bushing. Slick cementing stinger (2 7/8” EUE pin up).


Plug dropping cement head and heavy duty swivel or top drive liner cementing system (see Figure 1): Flag sub (4 1/2” IF). Lift nipple (4 1/2” IF). 2 Nos. Plug holder bushing. 2 Nos. Type 2 landing collar with shear-out sleeve. Connections 2 Nos. Float collar with baffle plate. to match 2 Nos. Type V set or side exit shoe. casing. 2 Nos. Type 2 liner wiper plug. 2 Nos. Drill pipe pump down plug (max. OD 4.563”, min. OD 2.25”). 2 Nos. 1 3/4” setting ball.

}

Notes: a) The liner hanger utilises VAM connections throughout. b) Pup joints and a radio-active marker may be required. c) If standard float collar is supplied by BP, then a catcher sub will be required. 4. 2.2


Liner Handling Equipment 2 Nos. 7” side door elevators. 2 Nos. 7” single joint elevators c/w swivel sling. 2 Nos. 7” rotary hand slips. (If non upset casing run then YC elevators and spider required.) 4 Nos. 7” klampon protectors. 2 Nos. Power tong dressed for 7” casing. 2 Nos. Hydraulic power unit for above. 2 Nos. Torque - turn units (if required). 6 Nos. Spare casing collars. 1 No. 7” casing spear c/w grapple/pack-off and stop ring. (Specify weight.) 4 1/2” IF connections (semi-submersibles). 7” springbow centralisers (as required). 7” stop collars (2 per centraliser). 1 No. 7” casing drift. API modified dope. Threadlock.

3.



2.

Dimension and part numbers of assemblies conform to those as per Figure 2 on Page 9 of this procedure. Measure all lengths, OD’s and ID’s.

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PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER HANGER WITH CPH PACKER PBR size and pressure rating.


Hanger pins: 2 Nos. 3/8” pins (giving shear rating 1166 psi).

5.


6.


7.


8.


9.


10. Free passage of setting ball through the assembly including the Type 2 wiper plug. 11. Seating of the setting ball in the landing collar and shear out sleeve. 12. Bore of PBR is compatible with outside diameter of compression set packer seal stem. 13. Free passage of pump down dart and setting ball through all tools, i.e. kelly cocks, bumper subs, crossover subs, drillpipe, etc.

Note: On semi-submersible units the use of the cementing kelly eliminates the use of bumper subs under normal weather conditions. However, 2 bumper subs with 60” stroke may be required in adverse weather conditions. The minimum drift of the bumper subs is 2 1/2” for 7” liners and 2” for 5” and 4 1/2” liners. Ensure passage of the ball and dart through the bumper subs. 14. Pressure test plug dropping head and flag sub assembly against kelly cock to 5000 psi. 15. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the “V” shoe and float collar. 16. Check the condition and rating of the cement manifold swival to confirm that it is heavy duty. 17. Prior to running the liner, install the pump down dart in the cement manifold and torque the lift sub to 12,000 ft/lbs. Mark the body and lift sub with white paint to indicate backing out. Make up the cement manifold to the cement kelly and lay out the assembly on the pipe rack. 18. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. 19. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded.

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Ensure all hanger and setting tool assembly connections are torqued up prior to running the liner.

2.

Run the liner assembly as per Figure 2 on page 9 of this section. The shoe track is to consist of the following: Side Exit Shoe. 2 joints of 7” casing. Float collar and baffle plate. 1 joint 7” casing. Type 2 landing collar with shear-out seat. Check the float equipment before RIH.

Notes: a) If drilling out of liner shoe is programmed, a side exit shoe with bakelite internals to be used. b) The distance between the catcher sub and landing collar may be increased dependent upon advice from drilling office. All connections including casing collars to one joint above the landing collar to be threadlocked. 3.


4.


5.


6.

Liner length to be such that when set ± 2m off bottom, the top of the tie-back packer will be a minimum of ± 1m below the nearest casing collar.

7.


Notes: a) Centralisers should never be positioned across a collar or stop collar on a liner. b) Gauge the centralisers prior to running. 8.




Notes: a) Use the stabbing guide. b) Install pup joints and radio-active marker as indicated in the drilling programme. c) If a radio-active marker is installed, ensure that it is only handled by service company personnel. 10. Make up hanger/setting tool assembly onto liner. Ensure no rotation of tool and setting sleeve. Do not apply torque across the hanger assembly, i.e. tong only on hanger bottom or top subs. Ensure that the setting tool and all other connections are made up properly.

Note: a) Start threads using a chain tong.

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PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER HANGER WITH CPH PACKER b)

Leaving the slips on the liner joint, pick up 1m to check that the connection is correctly made up.

11. Circulate the contents of the liner assembly. Pressure is not to exceed 700 psi. Visually check hanger for leaks and record pressures at various circulation rates up to 250 gpm. 12. Note weight of full liner on Martin Decker. 13. Check hanger for any damage to casing collar. Check the 4 x 3/8” shear pins on the split junk bonnet. Lower hanger assembly through rotary and set DP slips on the 5” lift nipple - do not set slips on the setting sleeve. Be careful to keep the hanger centred while lowering through the table to avoid damage to the piston, slips, etc. 14. RIH on 5” DP (do not use HWDP). Ensure the first 15 stands of pipe has protectors removed (to reduce the chance of cementing up the string and to allow the facility to washover if required). RIH filling every stand. Drift every stand to 2 1/2” minimum. Use the drillpipe wiper rubber and ensure string does not turn in the table.

Note: a) Do not exceed calculated running speeds. b) Always use a back-up tong when running the complete liner assembly. 15. Check up and down drags at the 9 5/8” casing shoe. Break circulation at the shoe. Ensure top drive swivel or cement head and cement lines made up before going into open hole. 16. Continue RIH. Pick up cement head or top drive swivel. Ensure running string is spaced out such that with the liner shoe 2m off bottom, there is enough overstand to set the liner on bottom if necessary. Drift all pup joints and singles picked up from the pipe deck.

Note: The 2RH Running Tool and HR Hydraulic Rotating Liner Hanger assembly allow the liner to be rotated while washing down through bridges in open hole as long as the 4 x 3/8” brass shear pins in the split junk bonnet in the PBR top remain intact (Baker do not recommend this. The shear screws are sheared out only if the liner weight is lost and 12,400 lbs force is applied to the liner top. This could occur either if a) the entire weight of the liner is lost due to a bridge whilst washing down, or b) by catching an upset on the hanger assembly (slips, cylinder, etc.) on the BOP stack, wellhead or other obstruction. To prevent shearing the pins, beware when running the liner assembly through the BOP and wellhead and limit slack-off weight when washing down through bridges to 80% of the liner weight. If the junk bonnet pins are sheared prematurely, rotation should not be applied until the hanger has been set. 17. Check string weight and up/down drags. 18. Lock the elevators and install the plug holder with kelly cock below. Wash down (with the compensator open on floating units), rotating only if necessary. Do not exceed 600 psi. Rig up cementing lines and test to 5000 psi against the kelly cock.

Note: Use sufficient Chiksan swings to allow for pick-up clear of the PBR. 19. Break circulation slowly. Wash and tag bottom with liner, mark the pipe and pull back 2m. Circulate bottoms up + 20% or 120% string volume whichever is the greater. In high temperature wells, extended circulation may be required. Do not exceed 600 psi initially and gradually increase circulation rate to a maximum of 250 gpm or 1000 psi.

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PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER HANGER WITH CPH PACKER Note: 250 gpm to avoid problems with the CPH packer and 1000 psi to avoid early setting of the liner.

20. Check string weight, with and without circulation. To prevent packing off, do not move the liner without circulating and do not slack off more than 80% of the liner weight.

Note: Do not exceed the maximum ECD achieved when drilling the 8 1/2” hole. 5.


Drop the setting ball through the 3” bull plug in the plug launching head or pull back and break out the kelly if hole conditions allow. Allow time for the ball to seat in the landing collar/shear out sub. Setting ball may be pumped down at a flowrate of 3 bbl/min. Limit pressure to 1000 psi. During this time check the pick-up and slack-off weights, tag bottom and pick up to the liner setting depth, i.e. full up stroke weight (total stroke of running tool is 1.5m).

Note: Standard 7” HSR hanger, 2 x 3/8” pins = 1166 psi shear. 2.

When the ball lands pressure up in stages to 1600 psi and set the hanger. Hold pressure for 10 minutes.

3.


When hanger has set, set down +/- 30000 lbs DP weight, mark the pipe and shear ball and seat at a pressure of +/- 2700 psi.

b)


4.

Establish circulation and circulate at various rates (i.e. 50, 100, 150 and 250 gpm) and record surface pressures. Check for losses. If losses are observed it may be necessary to restrict the cement displacement rate.

5.

Pick up to 15,000 lbs less than the theoretical running string weight. Rotate the running string 10 turns to the right. The hanger should release after 6 turns. Note the rotary torque.

6.

Pick up the running string weight plus 0.5m (use compensator on floating rigs) to ensure that the tool is released.

Note: a) Pick-up must be less than the length of the tailpipe which extends below the hanger. b) When using an RS pack-off, the running tool cannot be re-engaged. Note: As the allowable distance of travel with the standard running tool and PBR is very small, pulling any substantial distance will engage the packer setting dogs in the setting profile and result in premature setting of the packer and preclude cementing of the liner. When running the liner in deeper high angle wells, controlling the movement of the string over such small distances is impractical, even the inaccuracy of establishing the neutral point for release can, at these depths, leave stretch in the string which could potentially engage the packer setting dogs. Consideration must therefore be given to the following: a)

Not picking up the running string to ensure it is free from the liner. Hardly any instances of stuck running tools are recorded.

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PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER HANGER WITH CPH PACKER b)

7.

Section

Lengthen the setting sleeve and stinger to give a greater allowance for movement of the string without engaging the setting dogs or pulling the stinger and bushing out of the RS profile. CONSULT WITH DS ONSHORE. Such action will need to be taken as the equipment is being ordered.

Prior to cementing, set down 20,000 lbs weight on the hanger.

Note: Set down weight is dependent upon the pump-out forces when shearing out and bumping the liner wiper plug. This shear-out force increases considerably if inverted cups are used instead of the retrievable pack-off bushing. 8.

Break circulation and commence right hand rotation. 4-5 turns will transmit torque to the liner. Limit torque total to (cased hole torque + liner thread torque) x 80%. Establish rotation of liner at 15-20 rpm. Only rotate the liner when circulating. If rotation is not practical continue with cement operation.



10. After checking for backflow following the cement job, set the CPH packer by picking up the running tool 2.5m at the liner top. This will place the packer setting dogs above the CPH packer tie-back extension which is 3.4m long. Maintain 500 psi on the running string as the tailpipe is pulled as an indication when free. 11. Rotate the running string 6-10 turns to the right to ensure that the tool is free. Pick up on the running string but do not pull above the previous up stroke weight before the liner was set. If pickup weight exceeds the previous value, set down 20,000 lbs on the liner and put in additional righthand turns while observing rotary torque. If this does not work then the tool is stuck in the liner or cement.

Note: The pipe may be worked to 80% of pipe yield strength when the top drive swivel head is in use. 12. Pull the running tool above the CPH packer tie-back extension, then move the tool down until weight is taken on the packer top. 13-17,000 lbs down will shear the first pins and start to set the packer. 40,000 lbs down will shear the second set of pins and force the packer hold-down slips against the 9 5/8” casing. 13. Reverse circulate out the excess cement and spacer after pulling the stinger to just above the PBR. Avoid running into the PBR.

Note: Do not carry out casing test at this point, the liner lap will be tested on the cleanout trip. 14. On deviated wells, reciprocate pipe to ensure any low side cement is circulated out. 15. Monitor for contaminated cement returns (if OBM in use, refer to Section 3780/GEN). Pull out of hole with the running tool. Ensure hole is kept full. Monitor fill volume.


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PREPARATION AND RUNNING 7" BAKER (BROWN) HSR ROTATING LINER HANGER WITH CPH PACKER FIGURE 1 TOP DRIVE CONNECTION

BAILS


ELEVATOR


SETTING BALL

3" WECO CONNECTION




SAFETY LINE/CHAIN




911208/15

BP EXPLORATION


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PREPARATION AND RUNNING 7" TIW LINER





1.3

On exploration wells the 7” liner will normally form a production string with 9 5/8” casing and will usually only be run in the event of a well test. In some high pressure applications it may be necessary to tie back the liner to the wellhead.

1.4

When 7” casing is onboard, complete all general casing checks as per Sections 2000/GEN, 2900/GEN and 2950/GEN for chrome tubulars.

1.5

If a casing test is required prior to running the liner, run a positrieve packer to ± 50m above the 9 5/8” shoe. Test the 9 5/8” casing integrity by pressuring the 5” x 9 5/8” annulus to the programmed casing test pressure. The drilling office will confirm if the test is required.

1.6

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe to confirm DP tally and drift the DP on the way out of the hole, on the pre-liner check trip to a minimum of 2 1/2” (the OD of the metal body on the pump-down plug). If the pipe is not drifted when POH then it must be drifted when running the liner.

1.7


2.


2.1

TIW Liner Hanger Equipment 1.

7” x 9 5/8” liner hanger assembly comprising: 7” LG-6 setting collar with tie-back sleeve. RPOB nipple. Tandem cone hydro-hanger. Length of tie-back sleeve to be 6 ft for vertical wells and 15 ft for deep or deviated wells.

2.

Liner hanger running tool assembly comprising: Running tool with retrievable pack-off bushing. Upper slick tailpipe assembly. Lower tailpipe assembly with swivel and 7” liner wiper plug.

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Plug dropping cement head (4 1/2” IF conn) and heavy duty swivel. 2 Nos. HSSR landing collar with shear out ball seat. Connections 2 Nos. LS-2 set shoe. to match 2 Nos. Float collar. casing. 2 Nos. Drill pipe pump down plug. 2 Nos. Setting ball.

}

Note: Pup joints and a radio-active marker may be required. 4. 2.2


Liner Handling Equipment 2 Nos. 7” side door elevators. 2 Nos. 7” single joint elevators c/w swivel sling. 2 Nos. 7” rotary hand slips. (If non upset casing run then YC elevators and spider required.) 4 Nos. 7” klampon protectors. 2 Nos. Power tong dressed for 7” casing. 2 Nos. Hydraulic power unit for above. 2 Nos. Torque - turn units (if required). 6 Nos. Spare casing collars. 1 No. 7” casing spear c/w grapple/pack-off and stop ring. (Specify weight.) 7” springbow centralisers (as required). 7” stop collars (2 per centralisers). 1 No. 7” casing drift. API modified dope. Threadlock.

3.



2.

Dimensions and part numbers of assemblies conform to those as per Figure 1 on page 7 of this procedure. Measure all lengths, OD’s and ID’s.

3.


Note: On occasions a longer PBR may be supplied 4.

TIW liner wiper plug is used. Check compatibility of the liner wiper plug with the weight of the 7” casing.

5.

Size and number of liner wiper plug shear pins. This information should be available in the documentation with an estimated shear pressure.

6.

Free passage of the setting ball through the assembly including the liner wiper plug.

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7.

Seating of setting ball in the HS landing collar shear out seat.

8.

Bore of PBR is compatible with the outside diameter of the LG seal nipple, run below the compression set packer.

9.

Free passage of the setting ball and pump down plug through all tools, i.e. kelly cocks, bumper subs, crossover subs, drillpipe, etc.

Note: On semi-submersible units the use of the cementing kelly eliminates the use of the bumper subs under normal weather conditions. However, 2 bumper subs with 60” stroke may be required in adverse weather conditions. The minimum drift of the bumper subs is 2 1/2” for 7” liners and 2” for 5” and 4 1/2” liners. Ensure passage of the ball and dart through the bumper subs. 10. Pressure test the plug dropping head against the kelly cock to 5000 psi. 11. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the set shoe and float collar. 12. Check the condition and rating of the cement manifold swivel to confirm that it is heavy duty. 13. Prior to running the liner, install the pump down dart in the cement manifold and torque the lift sub to 12,000 ft/lbs. Mark the body and lift sub with white paint to indicate backing out. Make up the cement manifold to the cement kelly and lay out the assembly on the pipe rack. 14. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. 15. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded. 4.


Run the liner assembly as per Figure 1 on page 7 of this Section. The shoe track is to consist of the following: Side exit shoe. LS set shoe. 2 joints of casing. Conventional float collar. 2 joints of casing. Type HS landing collar with shear out seat.

Notes: a) If drilling out of liner shoe is programmed, a side exit shoe with Bakelite internals is to be used. b) The distance between the float collar and the landing collar may be increased dependent on advice from the drilling office. All connections including casing collars to one joint above the landing collar are to be threadlocked. 2.


3.


4.


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5.


6.




Note: Bakerlok all connections up to one joint above the landing collar. 8.


Note: a) Use the stabbing guide. b) Install pup joints and radio-active marker as indicated in the driling programme. c) If a radio-active marker is installed, ensure that it is only handled by service company personnel. 9.

Make up hanger/setting tool assembly. Ensure no rotation of tool and setting sleeve. Do not apply torque across the hanger assembly, i.e. tong only on the hanger bottom or top subs.

Note: a) Start threads using a chain tong. b) Leaving the slips on the liner joint, pick up 1m to check that the connection is correctly made up. 10. Circulate through the completed liner assembly. Pressure is not to exceed 750 psi. Visually check hanger for leaks and record pressures at various circulation rates. 11. Note weight of full liner on Martin Decker. 12. RIH on 5” DP (do not use HWDP). Ensure the first 15 stands of pipe have protectors removed (to reduce the chance of cementing up the string and to allow the facility to washover if required). RIH filling every stand. Drift every stand to 2 1/2” minimum. Use the drillpipe wiper rubber and ensure string does not turn in table.

Note: a) Do not exceed the calculated running speed. b) Always use a back-up tong when running the complete liner assembly. 13. Check up and down drags at the 9 5/8” casing shoe. 14. Continue RIH. Pick up cement kelly/plug holder/kelly cock. Ensure running string is spaced out such that with the liner shoe 2m off bottom, the kelly is at mid point, thus allowing enough overstand to set on bottom if necessary.

Note: Wash and work pipe through any tight spots but beware of packing off the annulus which may prematurely set the hanger. 15. Check string weight and up/down drags. 16. Lock the elevators and install the plug holder with kelly cock below. Wash down (with the compensator open on floating units). Do not exceed 750 psi surface pressure. Rig up cementing lines and test to 5,000 psi against the kelly cock.

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Note: Use sufficient Chiksan swings to allow for pick-up clear of the PBR. 17. Break circulation slowly. Tag bottom with liner, mark the pipe and pull back 2m. Circulate bottoms up + 20% or 120% string volume whichever is greater. Do not exceed 750 psi surface pressure. In high temperature wells extended circulation may be required. 18. Check string weight up and down, with and without circulation. To prevent packing off, do not move the liner without circulating.



Drop the setting ball through the plug launching head or pull back and break out the kelly if hole conditions allow. Allow time for it to seat in the HS landing collar.

Note: While the ball is dropping check the pick-up and slack-off weights, tag bottom and pick up the liner to setting depth, i.e. full up stroke weight. 2.

When the ball lands, pressure up in 500 psi stages to set the hanger. Setting pressure should be 1,200 psi.

3.

Check that the hanger has properly activated by slacking off the weight of the liner plus ± 5000 lbs. Liner weight should be lost before the shoe reaches bottom. If 1200 psi does not set the hanger, pick up and increase pressure in 200 psi increments, checking for a set after each increase. a)

If hanger has set, mark the pipe and shear ball from shear sub by increasing pressure in 200 psi stages to 2,500 psi when seat will shear and ball and seat will fall to float collar.

b)

If hanger has not set, sit liner on bottom and shear ball from the shear sub.

4.

Establish circulation and circulate at various rates (i.e. 50, 100, 150, 250, 300, 350 and 400 gpm) and record surface pressures. Check for losses. If losses are observed it may be necessary to restrict the cement displacement rate.

5.

Pick up to 15,000 lbs less than the theoretical running string weight.

6.

Rotate the running string 15-20 turns to the right. After 6-8 turns the hanger should release and further rotation will be torque free.

7.

Pick up the running string weight plus 1m to ensure that the tool is released.

Note: Pick-up must be less than the length of the tailpipe which extends below the hanger. 8.

Prior to cementing, set down 10,000/15,000 lbs weight on the hanger.

Note: Set down weight is dependent upon the pump-out forces when shearing out and bumping the liner wiper plug. This shear-out force increases considerably if inverted cups are used instead of packoff bushing. 9.


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Note: Do not exceed the maximum ECD achieved during drilling the 8 1/2” hole. 10. After checking for backflow, then POOH quickly to 500m above the top of the liner hanger.



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PREPARATION AND RUNNING 7" TIW LINER WITH INTEGRAL PACKER




The Type S liner packer is run to avoid sole reliance on the cement in the liner lap. It is weight set and provides the advantage that the cement above the lap can be circulated out immediately that the cement job is completed. The preferred option is to run an integral packer with the liner.

1.3


1.4


1.5

If a casing test is required prior to running the liner, run a positrieve packer to ± 50m above the 9 5/8” shoe. Test the 9 5/8” casing integrity by pressuring the 5” x 9 5/8” annulus to the programmed casing test pressure. The drilling office will confirm if the test is required.

1.6

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe to confirm DP tally and drift the DP on the way out of the hole, on the pre-liner trip to a minimum of 2 1/2” (the OD of the metal body of the pump-down plug). If the pipe is not drifted when POH then it must be drifted when running the liner.

1.7


2.


2.1

TIW Liner Hanger Equipment 1.

7” x 9 5/8” liner hanger assembly comprising: Type S liner packer with tie-back sleeve. RPOB nipple. Tandem cone RRP hydro-hanger. Length of tie-back sleeve to be 6 ft for vertical wells and 15 ft for deep or deviated wells.

2.

Liner hanger running tool assembly comprising: Running tool with retrievable pack-off bushing. Upper slick tailpipe assembly. Lower tailpipe assembly with swivel and 7” liner wiper plug.

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Plug dropping cement head (4 1/2” IF conn) and heavy duty swivel. 2 Nos. HSSR landing collar with shear-out ball seat. Connections 2 Nos. LS-2 set shoe. to match 2 Nos. Float collar. casing. 2 Nos. drill pipe pump down plug. 2 Nos. setting ball.

}


Cement Kelly and drive bushings (if required).

Liner Handling Equipment 2 Nos. 7” side door elevators. 2 Nos. 7” single joint elevators c/w swivel sling. 2 Nos. 7” rotary hand slips. (If non upset casing run then YC elevators and spider required). 4 Nos. 7” klampon protectors. 2 Nos. Power tong dressed for 7” casing. 2 Nos. Hydraulic power unit for above. 2 Nos. Torque - turn units (if required). 6 Nos. Spare casing collars. 1 No. 7” casing spear c/w grapple/pack-off and stop ring. (Specify weight.) 7” springbow centralisers (as required). 7” stop collars (2 per centralisers). 1 No. 7” casing drift (nylon if using chrome liner). API modified dope. Threadlock.

3.



2.

Dimensions and part numbers of assemblies conform to those as per Figure 1 on page 8 of this procedure. Measure all lengths, OD’s and ID’s.

3.


Note: On occasions a longer PBR will be supplied for deep or deviated wells. 4.

TIW liner wiper plug is used. Check compatibility of the liner wiper plug with the weight of the 7” casing.

5.


6.

Seals and packer elements for scoring or other damage.

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7.

Packer slips for cracks.

8.

Running tool pack-off seals fit the RPOB profile below the PBR.

9.

Free passage of the setting ball through the assembly, including the liner wiper plug.

10. Seating of the setting ball in the HSSR landing collar shear out seat. 11. Bore of PBR is compatible with the outside diameter of the LG seal nipple, run below the compression set packer. 12. Free passage of the setting ball and pump down plug through all tools, i.e. kelly cocks, bumper subs, crossover subs, drillpipe, etc.

Note: On semi-submersible units the use of the cementing kelly eliminates the use of the bumper subs under normal weather conditions. However, 2 bumper subs with 60” stroke may be required in adverse weather conditions. The minimum drift of the bumper subs is 2 1/2” for 7” liners and 2” for 5” and 4 1/2” liners. Ensure passage of the ball and dart through the bumper subs. 13. Round off the nose of the DP dart. 14. Check release mechanism of the running tool from the hanger. 15. Pressure test the plug dropping head against the kelly cock to the casing test pressure. 16. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the set shoe and float collar. 17. Check the condition and rating of the cement manifold swivel to confirm that it is heavy duty. 18. Prior to running the liner, install the pump down dart in the cement manifold and torque the lift sub to 12,000 ft/lbs. Mark the body and lift sub with white paint to indicate backing out. Make up the cement manifold to the cement kelly and lay out the assembly on the pipe rack. 19. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. 20. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded. 4.


Run the liner assembly as per Figure 1 on page 8 of this Section. The shoe track is to consist of the following: Side exit shoe. LS set shoe. 2 joints of casing. Conventional float collar. 2 joints of casing. Type HSSR landing collar with shear-out seat.

Note: a) If drilling out of the liner shoe is programmed, a side exit shoe with Bakelite internals is to be used. b) The distance between the float collar and the landing collar may be increased dependent on advice from the drilling office.

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All connections including casing collars to one joint above the landing collar are to be threadlocked. 2.


3.


4.


5.

Liner length to be such that when set ± 2m off bottom the top of the tie-back packer element will be a minimum of ± 1m below the nearest casing collar.

6.

On Clyde wells ensure that a chrome pup joint is placed at the top of the reservoir and place a radio-active collar on the first carbon steel joint above the chrome tubing.

7.



Make up the shoe track and check the float equipment. Note: Bakerlok all connections to one joint above the landing collar.

9.


Note: a) Use the stabbing guide. b) Install pup joints and radio-active marker as indicated in the drilling programme. c) If a radio-active marker is installed, ensure that it is only handled by service company personnel. 10. Make up hanger/setting tool assembly and liner wiper plug. Check the number and rating of the shear pins on the wiper plug. Ensure no rotation of tool and setting sleeve. Do not apply torque across the hanger assembly, i.e. tong only on hanger bottom or top subs.

Note: a) Start threads using a chain tong. b) Leaving the slips on the liner joint, pick up 1m to check that the connection is correctly made up. 11. Circulate through the completed liner assembly. Pressure is not to exceed 750 psi. Visually check hanger for leaks and record pressures at various circulation rates. 12. Note weight of full liner on Martin Decker. 13. RIH on 5” DP (do not use HWDP). Ensure the first 15 stands of pipe has protectors removed (to reduce the chance of cementing up the string and to allow the facility to washover if required). RIH filling every stand. Drift every stand to 2 1/2” minimum. Use the drill pipe wiper rubber and ensure string does not turn in the table.

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Note: a) Do not exceed the calculated running speed. b) Always use a back-up tong when running the complete liner assembly. 14. Check up and down drags at the 9 5/8” casing shoe. 15. Continue RIH. Pick up cement kelly/plug holder/kelly cock. Ensure running string is spaced out such that with the liner shoe 2m off bottom, there is sufficient overstand with the liner set on bottom.

Note: Wash and work pipe through any tight spots but beware of packing off the annulus which may prematurely set the hanger. 16. Check string weight and up/down drags. 17. Lock the elevators and install the plug holder with kelly cock below. Wash down (with the compensator open on floating units). Do not exceed 750 psi surface pressure. Rig up cementing lines and test to 5000 psi against the kelly cock.

Note: Use sufficient Chiksan swings to allow for pick-up clear of the PBR. 18. Break circulation slowly. Tag bottom with liner, mark the pipe and pull back 2m. Circulate bottoms up + 20% or 120% string volume whichever is greater. Do not exceed 750 psi surface pressure. In high temperature wells extended circulation may be required. 19. Check string weight up and down, with and without circulation. To prevent packing off, do not move the liner without circulating.



Drop the setting ball through the plug launching head or pull back and break out the kelly if hole conditions allow. Allow time for the ball to seat in the HSSR landing collar.

Note: While the ball is dropping, check the pick-up and slack-off weights, tag bottom and pick up the liner to the setting depth, i.e. full up stroke weight. 2.

Pressure up in 500 psi stages to set the hanger. Setting pressure should be 1200 psi.

3.

Check that the hanger has properly activated by slacking off the weight of the liner plus +/- 5000 lbs. Liner weight should be lost before the shoe reaches bottom. If 1200 psi does not set the hanger, pick up and increase the pressure in 200 psi increments, checking for a set after each increase. a)

If hanger has set, mark the pipe and shear the ball from the shear sub by increasing pressure in 200 psi stages to 2500 psi when the seat will shear and ball and seat will fall to the float collar.

b)

If hanger has not set, sit the liner on bottom and shear the ball from the shear sub.

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4.

Establish circulation and circulate at various rates (i.e. 50, 100, 150, 200, 250, 300, 350 and 400 gpm) and record surface pressures. Check for losses. If losses are observed it may be necessary to restrict the cement displacement rate.

5.

Pick up to 15,000 lbs less than the theoretical running string weight.

6.

Rotate the running string 15-20 turns to the right. After 6-8 turns the hanger should release and further rotation will be torque free.

7.

Pick up the running string weight plus 0.5m (use the compensator on floating rigs) to ensure that the tool is released.

Note: 1m travel puts the setting dogs very close to engaging the tie-back packer. Note: As the allowable distance of travel with the standard running tool and PBR is very small, pulling any substantial distance will engage the packer setting dogs in the setting profile and result in premature setting of the packer and preclude cementing of the liner. When running the liner in deeper high angle wells, controlling the movement of the string over such small distances is impractical, even the inaccuracy of establishing the neutral point for release can, at these depths, leave stretch in the string which could potentially engage the packer setting dogs. Consideration must therefore be given to the following:

8.

a)


b)

Lengthen the setting sleeve and stinger to give a greater allowance for movement of the string without engaging the setting dogs or pulling the stinger and bushing out of the bushing’s profile. CONSULT WITH DS ONSHORE. Such action will need to be taken as the equipment is being ordered.

Prior to cementing set down 10,000/15,000 lbs weight on the hanger.



Note: Do not exceed the maximum ECD achieved during drilling the 8 1/2” hole. 10. After checking for back flow, pick up the running string ± 2m (or more if PBR has been extended) to engage packer setting dogs in the recess. Slack off ± 30,000 lbs to set the packer (allowing for pipe stretch and hole drags). 11. Reverse circulate out the excess cement and spacer after pulling the stinger to just above the PBR. Avoid running into the PBR.

Note: Do not carry out casing test at this point, the liner lap will be tested on the cleanout trip. 12. On deviated wells, reciprocate pipe to ensure any low side cement is circulated out. 13. Monitor for contaminated cement returns (if OBM in use refer to Section 3780/GEN). Pull out of hole with the running tool. Ensure hole is kept full. Monitor fill volume.

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PREPARATION AND RUNNING 7" NODECO ROTATING LINER HANGER WITH TSP PACKER




The TSP packer is run to avoid sole reliance on the cement in the liner lap. It is weight set and gives the advantage that the cement above the lap can be circulated out immediately that the cement job is completed. The preferred option is to run an integral packer with the liner.

1.3


1.4


1.5


1.6


1.7

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe while POH to confirm DP tally. The liner running string must be drifted to a minimum of 2 1/2” (the OD of the metal body on the pump-down plug). A wireline retrievable dart/survey tool may be dropped as a drift. If the pipe is not drifted when POH, then it must be drifted when running the liner.

1.8


2.


2.1

Nodeco MHR Liner Hanger with TSP Packer 1.

7” x 9 5/8” liner hanger assembly comprising: TSP liner packer with PBR. MHR multicone hydraulic rotating hanger. Length of PBR to be 6 ft for vertical wells and 15 ft for deep or deviated wells.

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PREPARATION AND RUNNING 7" NODECO ROTATING LINER HANGER WITH TSP PACKER Liner hanger running tool assembly comprising: Shear-down junk bonnet. Type R running tool with RSM retrievable pack-off bushing. Slick cementing stinger (3 1/2” 8-ACME pin up).


Plug dropping cement head and heavy duty swivel or top drive liner cementing system (see Figure 1): Flag sub (4 1/2” IF). Lift nipple (4 1/2” IF). 2 Nos. Plug holder adaptor. 2 Nos. “WLC” landing collar with shear-out ball seal and catcher. 2 Nos. Float collar. 2 Nos. Type V set or side exit (double valve) shoe. 2 Nos. Liner wiper plug. 2 Nos. Drill pipe pump down plug (OD of metal body 2.50”). 2 Nos. 1 3/4” setting ball. Radio-active marker, if required.

}



Cement Kelly with drive bushings.

Liner Handling Equipment 2 Nos. 7” side door elevators. 2 Nos. 7” single joint elevators c/w swivel sling. 2 Nos. 7” rotary hand slips. (If non upset casing run then YC elevators and spider required.) 4 Nos. 7” klampon protectors. 2 Nos. Power tong dressed for 7” casing. 2 Nos. Hydraulic power unit for above. 2 Nos. Torque - turn units (if required). 6 Nos. Spare casing collars. 1 No. 7” casing spear c/w grapple/pack-off and stop ring. (Specify weight.) 7” springbow centralisers (as required). 7” stop collars (2 per centraliser). 1 No. 7” casing drift. API modified dope. Threadlock.

3.



2.

Dimension and part numbers of assemblies conform to those as per Figure 2 on Page 9 of this procedure. Measure all lengths and OD’s.

3.


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PREPARATION AND RUNNING 7" NODECO ROTATING LINER HANGER WITH TSP PACKER Note: On occasions a longer PBR may be supplied.

4.

Hanger pins: 4 Nos. brass screws (giving shear rating 1400 psi).

5.

Shear pins in ball seat of landing collar - 5 Nos. pins (shear rating 2600 psi).

6.

Packer shear pins: 3 Nos. (shear rating 16,000 lbs) plus 7 Nos. (shear rating 37,000 lbs).

7.

Mark the tool and sleeve extension with paint to show if tool begins to back off at any time prior to running.

8.


9.

Size and number of liner wiper plug shear pins. This information should be available in the documentation with an estimated shear pressure (normally +/- 1175 psi/4 screws).

10. Free passage of setting ball through the assembly including the Type 1 wiper plug. 11. Seating of the setting ball in the back-up landing collar ball seat. 12. Bore of PBR is compatible with outside diameter of compression set packer seal stem. 13. Free passage of pump down dart and setting ball by drifting all tools, i.e. kelly cocks, bumper subs, crossover subs, drillpipe, etc. Note: On semi-submersible units the use of the cementing kelly eliminates the use of bumper subs under normal weather conditions. However, 2 bumper subs with 60” stroke may be required in adverse weather conditions. The minimum drift of the bumper subs is 2 1/2” for 7” liners and 2” for 5” and 4 1/2” liners. Ensure passage of the ball and dart through the bumper subs. 14. Pressure test plug dropping head and flag sub assembly against kelly cock to 5000 psi. 15. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the shoe and float collar. 16. Check the condition and rating of the cement manifold swivel to confirm that it is heavy duty. 17. Prior to running the liner, install the pump down dart in the cement manifold. Make up the cement manifold to the cement kelly and lay out the assembly on the pipe rack.

Note: Using the Nodeco cement Kelly, the lift sub is not backed out. 18. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. 19. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded. 20. On shallow or deviated wells, HWDP may be required to allow the TSP packer to be set with 37,000 lbs downward force.

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2.

Run the liner assembly as per Figure 2 on page 9 of this section. The shoe track is to consist of the following: Side Exit Shoe. 1 joint of 7” casing. Float collar. 2 joints of 7” casing. “WLC” landing collar c/w catcher and shear-out ball seat. Check the float equipment before RIH.

Notes: a) If drilling out of liner shoe is programmed, a side exit shoe with bakelite internals to be used. b) The distance between the landing collar and the float collar may be increased dependent upon advice from drilling office. All connections including casing collars to one joint above the landing collar to be threadlocked. 3.


4.


5.


6.


7.




Note: Bakerlok all connections on the first 4 joints. Bakerlok friction factor = 1.6. 9.


Note: a) Use the stabbing guide. b) Install pup joints and radio-active marker as indicated in the drilling programme. c) If a radio-active marker is installed, ensure that it is only handled by service company personnel. 10. Make up hanger/setting tool assembly complete with liner wiper plug onto liner. Ensure no rotation of tool and setting sleeve. Do not apply torque across the hanger assembly, i.e. tong only on hanger bottom or top subs. Ensure that the setting tool and all other connections are made up properly.

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PREPARATION AND RUNNING 7" NODECO ROTATING LINER HANGER WITH TSP PACKER Note: a) Start threads using a chain tong. b) Leaving the slips on the liner joint, pick up 1m to check that the connection is correctly made up.

11. Circulate the contents of the liner assembly and record pressures at 2, 4, 6 and 8 BPM to determine the approximate liner ECD in the 9 5/8” casing. Pressure is not to exceed 500 psi. Visually check hanger for leaks and record pressures at various circulation rates up to 250 gpm. 12. Note weight of full liner on Martin Decker. 13. Check hanger for any damage. Check the shear pin on the split junk bonnet. Lower hanger assembly through rotary and set DP slips on the 5” lift nipple - do not set slips on the setting sleeve. Be careful to keep the hanger centred while lowering through the table to avoid damage to the piston, slips, etc. 14. RIH on 5” DP. Ensure the first 15 stands of pipe has protectors removed (to reduce the chance of cementing up the string and to allow the facility to washover if required). RIH filling every stand. Drift every stand to 2 1/2” minimum. Use the drillpipe wiper rubber and ensure string does not turn in the table.

Note: a) Do not exceed calculated running speeds. b) Always use a back-up tong when running the complete liner assembly. 15. Check up and down drags at the 9 5/8” casing shoe. Break circulation but do not exceed 1000 psi surface pressure. Ensure top drive swivel or cement head and cement lines made up before going into open hole. 16. Continue RIH. Lock the elevators and pick up cement head or top drive swivel. Ensure running string is spaced out such that with the liner shoe 2m off bottom, there is enough overstand to set the liner on bottom if necessary. Drift all pup joints and singles picked up from the pipe deck.

Note: The Type R Running Tool and MHR Hydraulic Rotating Liner Hanger assembly allow the liner to be rotated while washing down through bridges in open hole as long as the brass shear pin in the split junk bonnet in the PBR top remains intact. The shear screw is sheared out only if the liner weight is lost and force is applied to the liner top. This could occur either if a) the entire weight of the liner is lost due to a bridge whilst washing down, or b) by catching an upset on the hanger assembly (slips, cylinder, etc.) on the BOP stack, wellhead or other obstruction. To prevent shearing the pin, beware when running the liner assembly through the BOP and wellhead and limit slack-off weight when washing down through bridges to 80% of the liner weight. If the junk bonnet pin is sheared prematurely, rotation should not be applied until the hanger has been set. 17. Check string weight and up/down drags. 18. Wash down (with the compensator open on floating units), rotating only if necessary. Do not exceed 1000 psi. Rig up cementing lines and test to 5000 psi against the cement head.

Note: Use sufficient Chiksan swings to allow for pick-up clear of the PBR. 19. Break circulation by staging up pressure in 500 psi increments every 5 minutes. Wash and tag bottom with liner, mark the pipe and pull back 2m. Circulate bottoms up + 20% or 120% string volume whichever is the greater. In high temperature wells, extended circulation may be required.

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PREPARATION AND RUNNING 7" NODECO ROTATING LINER HANGER WITH TSP PACKER Do not exceed 1000 psi initially. Slowly increase the circulating pressure to a maximum of 1500 psi and condition the mud as required.

Note: 1400 psi internal pressure will set the liner if circulation is not achieved. 20. Check string weight, with and without circulation and record circulating pressures. To prevent packing off, do not move the liner without circulating and do not slack off more than 80% of the liner weight.

Note: Do not exceed the maximum ECD achieved when drilling the 8 1/2” hole. 5.


Drop the setting ball through the ball launcher in the plug launching head. Allow time for the ball to seat in the landing collar/shear out sub. Setting ball may be pumped down at a flowrate of 3 bbl/min. Limit pressure to 700 psi. During this time check the pick-up and slack-off weights, tag bottom and pick up to the liner setting depth.

Note: a) The ball should take approximately 2 - 3 minutes per 300m to land on its seat. b) Standard 7” MHR hanger, 4 screws = 1400 psi shear. 2.

When the ball lands pressure up in stages to 1600 psi to set the hanger.

3.


When hanger has set, set down +/- 20000 lbs DP weight, mark the pipe and shear ball and seat at a pressure of +/- 2600 psi. Shear-out is indicated by the ability to circulate at a similar rate and pressure as noted prior to dropping the ball.

b)


4.


5.

Pick up to 15,000 lbs less than the theoretical running string weight. Rotate the running string 10 turns to the right (the setting tool should be released after 6 turns at the tool). Note the rotary torque and check for residual torque.

6.

Pick up the running string weight plus 0.5m (use the compensator on Floating Rigs) to ensure that the tool is released.

Note: a) Pick-up must not exceed half the distance from the packer actuator to the top of the PBR or half the distance from the pick-up sub to the retrievable pack-off bushing, whichever is less. b) Confirm that the pick-up weight is minus the weight of the liner. Note: As the allowable distance of travel with the standard running tool and PBR is very small, pulling any substantial distance will engage the packer setting dogs in the setting profile and result in premature setting of the packer and preclude cementing of the liner.

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PREPARATION AND RUNNING 7" NODECO ROTATING LINER HANGER WITH TSP PACKER When running the liner in deeper high angle wells, controlling the movement of the string over such small distances is impractical, even the inaccuracy of establishing the neutral point for release can, at these depths, leave stretch in the string which could potentially engage the packer setting dogs. Consideration must therefore be given to the following:

7.

a)


b)



Note: Set down weight is dependent upon the pump-out forces when shearing out and bumping the liner wiper plug. This shear-out force increases considerably if inverted cups are used instead of the retrievable pack-off bushing (Nodeco do not normally supply swab cups). 8.

Break circulation and commence right hand rotation. 2-3 turns will transmit torque to the liner. Limit torque total to (cased hole torque + liner thread torque) x 80%. Establish rotation of liner at 15-20 rpm. Only rotate the liner when circulating. If rotation is not practical continue with cement operation.



10. After checking for backflow following the cement job, set the TSP packer by picking up the running tool 3m at the liner top. This will place the packer setting dogs above the tie-back extension which is 3.4m long. 11. Slack off and set weight down to set the TSP packer. Approximately 16,000 lbs will shear the first set of pins and allow the packer to begin setting. Increasing the set down weight to 37,000 lbs will shear the second set of pins and force the packer hold-down slips against the 9 5/8” casing. 12. Reverse circulate out the excess cement and spacer after pulling the stinger to just above the PBR. Avoid running into the PBR.

Note: Do not carry out casing test at this point, the liner lap will be tested on the cleanout trip. 13. On deviated wells, reciprocate the string to ensure any low side cement is circulated out. 14. Monitor for contaminated cement returns (if OBM is in use refer to Section 3780/GEN). Pull out of hole with the running tool. Ensure hole is kept full. Monitor fill volume.


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PREPARATION AND RUNNING 7" NODECO ROTATING LINER HANGER WITH TSP PACKER FIGURE 1 TOP DRIVE CONNECTION

BAILS


ELEVATOR


SETTING BALL

3" WECO CONNECTION




SAFETY LINE/CHAIN




911208/15

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PREPARATION AND RUNNING 7" LINDSEY-ARROW HSB-SC LINER HANGER WITH WM-P PACKER




The WM-P liner packer is run to avoid sole reliance on the cement in the liner lap. It is weight set and provides the advantage that the cement above the lap can be circulated out immediately that the cement job is completed.

1.3


1.4


1.5

If a casing test is required prior to running the liner, run a positrieve packer to +/- 50m above the 9 5/8” shoe. Test the 9 5/8” casing integrity by pressuring the 5” x 9 5/8” annulus to the programmed test pressure. The drilling office will confirm if the test is required.

1.6

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe to confirm the DP tally and drift the DP on the way out of the hole to a minimum of 2 1/2” (the OD of the metal body of the pump down plug) on the pre-liner trip. If the pipe is not drifted when POH, then it must be drifted when running the liner.

1.7


2.


2.1

Lindsey-Arrow Liner Hanger Equipment 1.

7” x 9 5/8” liner hanger assembly comprising: Model WM-P weight set packer with 15 ft tie-back receptacle. Model HSB-SC single cone hydraulic hanger.

2.

Liner hanger running tool assembly comprising: Model D setting tool and tamping dog assembly (4 1/2” IF conn). Retrievable cement bushing and polished slick joint.

Note: It is normal for two complete assemblies of items 1 and 2 to be assembled and tested by the supplier and to be shipped to the rig in protective cradles.

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PREPARATION AND RUNNING 7" LINDSEY-ARROW HSB-SC LINER HANGER WITH WM-P PACKER Cementing manifold with ball dropping sub and swivel and flag sub. 2 Nos. 2 Nos. 2 Nos. 2 Nos. 2 Nos. 2 Nos.

Float shoe with double ball float. Float collar with single ball float. BCB landing collar. Liner wiper plug. Drill pipe wiper plug. Setting ball.

}



Cementing kelly complete with drive bushing and locking dogs.

Liner Handling Equipment 2 Nos. 7” side door elevators. 2 Nos. 7” single joint elevators c/w swivel sling. 2 Nos. 7” rotary hand slips. (If non upset casing run then YC elevators and spider required.) 4 Nos. 7” klampon protectors. 2 Nos. Power tong dressed for 7” casing. 2 Nos. Hydraulic power unit for above. 2 Nos. Torque - turn units (if required). 6 Nos. Spare casing collars. 1 No. Crossover 4 1/2” IF pin x 6 5/8” full hole box. 1 No. Crossover 6 5/8” FH pin x 4 1/2” IF box with 10” internal taper. 1 No. Liner polishing/dressing mill assembly. 1 No. 7” casing spear c/w grapple/pack-off and stop ring. (Specify weight.) 7” springbow centralisers (as required). 7” stop collars (2 per centraliser). 1 No. 7” casing drift. API modified dope. Threadlock.

3.



2.


3.


4.

Correct liner wiper plug is used. Check compatibility of the liner wiper plug with the weight of the 7” casing.

5.


6.


7.


8.

Free passage of the setting ball through the assembly, including the liner wiper plug.

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PREPARATION AND RUNNING 7" LINDSEY-ARROW HSB-SC LINER HANGER WITH WM-P PACKER Seating of the setting ball in the landing collar shear-out seat.

10. Free passage of the setting ball and pump-down plug through all tools, i.e. kelly cocks, bumper subs, crossover subs, drillpipe, etc.

Note: On semi-submersible units the use of the cementing kelly eliminates the use of bumper subs under normal weather conditions. However, 2 bumper subs with 60” stroke may be required in adverse weather conditions. The minimum drift of the bumper subs is 2 1/2” for 7” liners and 2” for 5” and 4 1/2” liners. Ensure passage of the ball and dart through the bumper subs. 11. Check release mechanism of the running tool from the hanger. 12. Pressure test the plug dropping head against the kelly cock to the casing test pressure. 13. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the shoe and float collar. 14. Check the condition and rating of the cement manifold swivel to confirm that it is heavy duty. 15. Prior to running the liner, make up the cementing manifold onto the cementing kelly and lay out the assembly on the pipe rack. 16. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. 17. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded. 4.


Run the liner assembly as per Figure 1 on page 7 of this section. The shoe track is to consist of the following: Shoe with double float. 2 joints of casing. Conventional float collar. 1 joint of casing. Model BCB landing collar.

Notes: a) If drilling out of the liner shoe is programmed, a side exit shoe with Bakelite internals is to be used. b) The distance between the float collar and the landing collar may be increased dependent on advice from the drilling office. 2.


3.


4.


5.

Liner length to be such that when set +/- 2m off bottom the top of the tie-back packer element will be a minimum of +/- 1m below the nearest casing collar.

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PREPARATION AND RUNNING 7" LINDSEY-ARROW HSB-SC LINER HANGER WITH WM-P PACKER Centraliser programme to be confirmed by drilling office (refer also to Section 2010/GEN).



Note: a) On Miller producer wells, the landing collar is incorporated in the 7” x 6 5/8” crossover. b) Check that 10 shear screws on the landing collar are installed giving a shear value of 2800 3000 psi. c) Threadlock all connections to 1 joint above the landing collar. 8.


Note: a) Use the stabbing guide. b) If a high chrome liner is in use, refer to Section 2950/GEN. c) Install pup joints and radio-active marker as indicated in the drilling programme. d) If a radio-active marker is installed, ensure that it is only handled by service company personnel. 9.

Make up the hanger/setting tool assembly.

Note: a) Ensure that there is no rotation of the tool and setting sleeve on make-up. Do not apply torque across the hanger assembly, i.e. tong only on the hanger bottom or top subs. Start threads using a chain tong and check that all left hand threads on the running tool are all made up. After make-up and leaving the slips on the liner joint, pick up 1m to check that the connection is correctly made up. b) Ensure that the hanger shear screws collate with the shear valve on the setting piston. Each hanger shear screw is 1/4” x 20mm with a 300 psi shear value. There are normally 5 shear screws per hanger. However, brass shear screws have a shear tolerance of +/- 15% which may mean that more or less than 5 shear screws are required to achieve a shear pressure of 1500 psi. c) Check the number and rating of the shear pins on the liner wiper plug. 10. Circulate the liner contents through the complete liner assembly. Pressure is not to exceed 700 psi. Visually check the hanger for leaks and record pressures at various circulation rates. 11. Note the up and down weights of the full liner. 12. RIH on DP (do not use HWDP). Ensure the first 15 stands of pipe has protectors removed (to reduce the chance of cementing up the string and to allow the facility to washover if required). RIH filling every stand. Drift every stand to 2 1/2” minimum. Use the drillpipe wiper rubber and ensure the string does not turn in the table.

Note: a) Do not exceed the calculated running speed. b) Always use a back-up tong when running the complete liner assembly. 13. Check up and down drags at the 9 5/8” casing shoe. 14. Continue RIH. Pick up cement manifold/kelly assembly to tag bottom (with the compensator open on floating rigs). Ensure that the running string is spaced out such that with the liner shoe 2m off bottom, there is sufficient overstand with the liner set bottom. Once bottom is tagged, pull back 2m.

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PREPARATION AND RUNNING 7" LINDSEY-ARROW HSB-SC LINER HANGER WITH WM-P PACKER Note: Wash and work pipe through any tight spots but beware of packing off the annulus which may prematurely set the hanger.

15. Rig up cementing lines and test to 5000 psi against the kelly cock. Break circulation slowly and circulate bottoms up + 20% or 120% string volume whichever is greater. Do not exceed 800 psi surface pressure. In high temperature wells, extended circulation may be required.

Note: Use sufficient Chiksan swings to allow for pick-up clear of the PBR. 16. Check string weight up and down, with and without circulation. To prevent packing off, do not move the liner without circulating.



Drop the setting ball through the plug launching head. Circulate the ball down at 2 - 3 bbls/min. or as recommended by the service operator.

Note: a) Watch the flag sub closely when dropping the ball to ensure that it has been released. b) While the ball is dropping, check up/down weights and ensure that the liner is at the correct setting depth. 2.

Once the ball has seated, slowly increase the pump pressure to 1500 psi.

3.

Check that the hanger has properly activated by slacking off the total weight of the liner. The liner weight should be lost before the shoe reaches bottom. If the hanger has set, increase the set down weight to the weight of the liner plus 10,000 lbs of drillpipe weight. This causes the rotational locking dogs on the running tool to move out of the locking slots in the setting adapter with the thrust bearing moving down against the bearing shoulder in the setting adapter. With the locking dogs and thrust bearing in this position, load can be taken by the bearing and the left hand releasing nut is now in the neutral position.

4.

Slowly increase the pump pressure to +/- 3000 psi until the seat in the landing collar shears. A pressure drop will indicate a successful shear and allow circulation to resume. Verify that pressures and circulation rates are similar to those prior to setting the hanger. Record surface pressures at various circulation rates (i.e. 50, 100, 150, 200, 250, 300, 350 and 400 gpm). If losses are observed, it may be necessary to restrict the cement displacement rate.

5.

With the liner weight plus 10,000 lbs of drillpipe weight remaining on the hanger slipos, rotate the running string 30 torque-free turns to the right to disengage the running tool.

6.

Pick up the setting tool 2m (using the compensator on floating units) to confirm that the setting tool is released.

Note: As the allowable distance of travel with the standard running tool and PBR is very small, pulling any substantial distance will engage the packer setting dogs in the setting profile and result in premature setting of the packer and preclude cementing of the liner. When running the liner in deeper high angle wells, controlling the movement of the string over such small distances is impractical, even the inaccuracy of establishing the neutral point for

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PREPARATION AND RUNNING 7" LINDSEY-ARROW HSB-SC LINER HANGER WITH WM-P PACKER release can, at these depths, leave stretch in the string which could potentially engage the packer setting dogs. Consideration must therefore be given to the following:

7.

a)


b)

Lengthen the setting sleeve and stinger to give a greater allowance for movement of the string without engaging the setting dogs or pulling the stinger and bushing out of the bushing profile. CONSULT WITH DS ONSHORE. Such action will need to be taken as the equipment is being ordered.





After checking for backflow, pick up the running string to move the Tamping Dog Assembly from inside the Tie-Back Receptacle to allow the dogs to spring out to a diameter greater than the PBR bore.

Note: The distance to be picked up is determined by the length of the Tie-Back Receptacle. 10. Set down +/- 60,000 lbs which will allow the dogs to engage the top of the PBR. Repeat the process of picking up and setting down twice more to ensure complete packing off of the weight set packer. 11. Pick up the running string so that the tailpipe is +/- 10m above the top of the PBR. The lower end of the slick joint has a reduced OD which allows the dogs of the retrievable cement bushing (RCB) to retract from the RCB profile in the setting adapter. Picking up moves the reduced OD to a position directly under the RCB dogs. The coupling at the bottom of the slick joint then picks up the RCB, allowing the dogs to collapse onto the reduced OD of the slick joint. This enables the RCB to be pulled out of the setting adapter and retrieved along with the running tool. 12. Reverse circulate out the excess cement and spacer after pulling the stinger to just above the PBR. Avoid running into the PBR.

Note: Do not carry out casing test at this point, the liner lap will be tested on the cleanout trip. 13. On deviated wells, reciprocate the string to ensure any low side cement is circulated out. 14. Monitor for contaminated cement returns (if OBM in use refer to Section 3780/GEN). Pull out of hole with the running tool. Ensure hole is kept full. Monitor fill volume.


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PREPARATION AND RUNNING 7" LINDSEY-ARROW HSB-SC LINER HANGER WITH WM-P PACKER


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PREPARATION AND RUNNING 7" ENACO/TIW ROTATING LINER HANGER WITH 'S' PACKER AND SJ-T MECHANICAL ROTATING TOOL

1.

PRE-RUNNING CHECKS

1.1

Hanger Loading Forces Determine the maximum loading possible on the casing during the hanger setting procedure. Take into account the following forces, which will be cumulative: a) b) c) d) e)

Liner hanging weight in mud. Internal pressure to initially set the hanger and shear ball seat. Pressure to bump plug (if greater than (b)). Running string setdown weight prior to cementing (if required and stated in the programme). Setdown weight on integral liner packer.

If calculations indicate loadings are within 15% of casing design loads, ie calculated hanger load rating, alternative hanger designs may have to be considered. If single cone hanger equipment will not satisfy casing loading criteria, multicone equipment will be used. 1.2

TIW 'S' packer is run to avoid sole reliance on the cement in the liner lap. It is weight set and gives the advantage that the cement above the lap can be circulated out immediately that the cement job is completed. The preferred option is to run an integral packer with the liner. Note: Do not pressure test the packer before the cement has set, as this also imposes high additional forces on the hanger and casing.

1.3

When 7" casing is onboard, complete all general casing checks as per Sections 2000/GEN and 2900/GEN.

1.4

Prior to running the liner, baseline torque needs to be established in order to develop safe surface torque limitations while maintaining sufficient torque to account for wellbore resistance. The following procedure is recommended: 1)

During the clean-up trip, rotate the drillstring 5 to 10ft off bottom at 10, 15 and 20rpm and circulate at the required rate for liner cementation. Usually, the torque required for this operation is comparable to the torque required for liner rotation.

2)

Rotate the drillstring with the bit inside the casing at a depth equal to the liner top.

3)

Using this information, the maximum allowable surface torque may be calculated by adding the maximum casing make-up torque to the torque required for drill string rotation at or near the liner top. The Operator may elect to use either 80 or 90% of the total as the maximum allowable surface torque.

1.5

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe while POH to confirm DP tally. The liner running string must be drifted to a minimum of 2 1/2". A wireline retrievable dart/survey tool may be dropped as a drift. If the pipe is not drifted when POH, then it must be drifted whilst running the liner.

1.6



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2.

EQUIPMENT CHECKLIST

2.1

TIW Rotating Liner Hanger with Integral Packer 7" x 9 5/8" liner hanger assembly comprising: A)

B)

i)

2 x TIW 'S-10' integral packer c/w RPOB profile and 'C' clutch and 10ft. Tieback receptacle. New Vam pin or box down connections.

ii)

2 x TIW RRP-tandem cone rotating liner hanger. New Vam box x pin or pin x pin connections.

i)

TIW SJ-T rotating liner running tool c/w junk bonnet, RPOB and slick joint. Note: Items 2.1 A) i) and ii) will be supplied assembled with Item 2.1 B) i) having been pressure and function tested at Enaco PLC's workshop facility.

C.

Two of each of the following items will also be supplied to run and cement the liner. These will be along with the items detailed in 2.1 A) and B) in a certified cargo basket: i)

7" TIW HS-SR landing collar c/w shear-out ball seat and catcher, New Vam box x pin connections (2500psi standard shear).

ii)

7" TIW liner wiper plug c/w latch ring pinned with 4 x 3/8" shear pins to give 1200psi shear.

iii) 5" TIW drillpipe pumpdown plug. Note: Items detailed in 2.1 C) i), ii), iii) above will be supplied incorporating the TIW PDC drillable anti-rotation system when it is likely the shoetrack is to be drilled out. iv) 7" TIW float collar w/single valve, New Vam box and pin connections. v)

7" TIW float shoe w/double valve, New Vam box connection.

vi) 1 3/4" TIW setting ball - bronze or 2.45 SG Bakerlite material for PDC drillout. Radioactive marker. Note: Pup joints and a radioactive marker will be required. Surface Equipment: a)

Top drive manifold c/w 10ft pup joint, ball dropping sub facility and flag indicator incorporating a plug release system. See Figure 1. The drillpipe pumpdown plug will normally be installed at Enaco PLC's workshop facility. OR

b) 2.2

Cement Kelly c/w heavy duty, cement head and heavy duty swivel c/w indicator sub (as an alternative to (a)).

Liner Handling Equipment 2 Nos. 7" side-door elevators 2 Nos. 7" single joint elevators c/w swivel sling 2 Nos. 7" rotary hand slips 4 Nos. 7" Klampon protectors 2 Nos. power tong dressed for 7" casing 2 Nos. hydraulic power unit for above 2 Nos. torque-turn units (if required)


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6 Nos. spare casing collars 1 No. 7" casing spear c/w grapple/pack-off and stop ring (specify weight) 7" bow spring centralisers (as required) 7" stop collars (2 per centraliser) 1 No. 7" casing drift API modified dope Threadlock 3.


Weight and grade of hanger and packer.

2.

Dimensions and part numbers of assemblies conform to those as per Figure 2. Measure all lengths and ODs.

3.

PBR size and pressure rating. Note: On occasions a longer PBR may be supplied.

4.

Hanger pins: 3 Nos. 1/4" brass screws (giving shear rating 1200psi standard); or optional 4 Nos. 1/4" brass screws (giving shear rating 1600psi standard).

5.

Ball seat in landing collar; 2500psi standard - 3000psi option available.

6.

Packer shear pins: 8 Nos. x 3/8" (shear rating 37,000 lbs).

7.

Mark the tool and lower packer body with paint to show if tool begins to back off any time prior to running.

8.

Check compatibility of the liner wiper plugs with the weight of the 7" casing.

9.

Size and number of liner wiper plug shear pins. This information should be available in QA/QC documentation with an estimated shear pressure of +/- 1200 psi 4 x 3/8" screws.

10. Free passage of setting ball through the wiper plugs. 11. Seating of the setting ball in the back-up landing collar ball seat. 12. Bore of PBR is compatible with outside diameter of compression set packer seal stem. 13. Free passage of pumpdown dart and setting ball by drifting all tools, ie Kelly cocks, bumper subs, crossover subs, drillpipe, etc. 14. The top drive manifold has been tested to 5000psi onshore. 15. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the shoe and float collar. 16. Check the condition and rating of the cement manifold swivel to confirm that it is heavy duty. 17. Prior to running the liner, if a top drive manifold and swivel is not to be utilised, install the pumpdown plugs and setting ball in the cement manifold. Make up the cement manifold to the cement Kelly and lay out the assembly on the pipe rack. If utilising the TIW top drive cementing system, the drillpipe dart should have been loaded onshore at Enaco workshop.


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18. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. In deviated wells this may be difficult. 19. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded. 20. On shallow or deviated wells, HWDP may be required to allow the 'S' packer to be set with 60,000 lbs downward force. 4.


Ensure that all hanger and setting tool assembly connections are torqued up prior to running the liner.

2.

Run the liner assembly as per Figure 2. The shoe track is to consist of the following: TIW float shoe 1 joint of 7" casing TIW float collar 2 joints of 7" casing TIW HS-SR landing collar c/w catcher and shear-out ball seat. Check the float equipment before RIH. Note: If drilling out of liner shoe is programmed, a TIW PDC drillable float collar and shoe to be used.

3.

The required setting depth of the landing collar should be checked with the drilling office prior to the pre-liner clean-out trip. This will depend on the lowermost test/completion interval and the required sump for the TCP guns to be dropped into the sump.

4.

Liner lap will be 500ft unless otherwise specified. A pup joint is to be set at the top of the reservoir.

5.

A radioactive collar will be positioned at the crossover from 13% chrome to the conventional pipe. Chrome pipe must be used from the landing collar to two joints above the anticipated completion packer setting depth. The completion packer will be set +/- 200ft above the top perforation. Two extra joints are run to allow for workovers. High collapse casing must be used in the salt section, special 22% chrome duplex 32 lb/ft joints will be available. If used, the Duplex will require New Vam to Vam Ace crossovers.

6.

Liner length to be such that when set the shoe is +/- 6ft off bottom and the top of the tieback packer will be a minimum of +/- 3 ft below the nearest 9 5/8" casing collar.

7.

Centraliser programme as per Drilling Programme.

8.

Make up the shoe track and check the float equipment. Notes: a)

Use the stabbing guide.

b)

Install pup joints and radioactive marker as indicated in the Drilling Programme.

c)

If a radioactive marker is installed, ensure that it is only handled by service company personnel.

d)

Check surge pressures/running speeds.


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PREPARATION AND RUNNING 7" ENACO/TIW ROTATING LINER HANGER WITH 'S' PACKER AND SJ-T MECHANICAL ROTATING TOOL e)

9.

Section

At the crossover to HC.95 check the number of chrome joints remaining on the pipe deck. Check the number and grade of joints on the pipe deck prior to picking up the hanger assembly.

Make up and Bakerlok TIW setshoe on first joint of liner.

10. Make up and Bakerlok TIW float collar on top of first joint of liner. Check floats are functioning properly. 11. Make up and Bakerlok TIW HS-SR landing collar, normally two joints above float collar. 12. Make up remainder of liner. Fill every joint. Run in hole controlling the running speed. If centralisers are used, they must be the type that permit the liner to be rotated through the centraliser. 13. After making up last joint of liner, fill pipe and check string weight. 14. The TIW hanger assembly should now be picked up, the liner wiper plug installed on the bottom of the slick joint and the hanger assembly made up to the liner. 15. Record up and down weights of the liner. 16. Rabbit all stands of drillpipe and run in hole. Control running speed. Fill pipe every five stands. 17. Run in hole on 5" drillpipe. Ensure that the first 15 stands of pipe have protectors removed (to reduce the chance of cementing up the string and to allow the facility to washover if required). Run in hole filling every stand. Drift every stand to 2 1/2" minimum. Use the drillpipe wiper rubber and ensure that the string does not turn in the table. Notes: a) b)

Do not exceed calculated running speeds. Always use a back-up tong when running the complete liner assembly.

18. Before setshoe starts out in open hole, break circulation, record rate and pressure. Do not exceed 800psi. Note up/down weights at this time. Establish rotation, record torque at 10, 15 and 20rpm (do not exceed maximum allowable torque). 19. Continue in hole with liner. Wash last stand to approximately 30ft from bottom. Do not exceed 60% of the pre-set hanger shear pressure which can be found on the QA/QC drawings provided to the rig and onshore EDSL Engineer. Note:

The TIW SJ-T type running tool and TIW hydraulic rotating liner hanger assembly allow the liner to be rotated while washing down through bridges in open hole as long as the brass shear pins in the tool remain intact. The shear screw is sheared out only if the liner weight is lost and force is applied to the running tool. This could occur either if (a) the entire weight of the liner is lost due to a bridge whilst washing down, or (b) by catching an upset on the hanger assembly (slips, cylinders, etc) on the BOP stack, wellhead or other obstruction. To prevent shearing the pin, beware when running the liner assembly through the BOP and wellhead and limit slack-off weight when washing down through bridges to 80% of the liner weight. If the running tool pins are sheared prematurely, rotation should not be applied until the hanger has been set.


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20. Check string weight and up/down drags. Wash down rotating only if necessary. Do not exceed 800psi. Rig up cementing lines and test to 5000 psi against the cement head. Note:

Use sufficient Chiksan swings to allow for pick-up clear of the PBR.

Break circulation by staging up pressure in 500psi increments every 5 minutes. Wash and tag bottom with liner, mark the pipe and pull back 6ft. Circulate bottoms up + 20% or 120% string volume whichever is the greater. In high temperature wells, extended circulation may be required. Do not exceed 1000psi initially. Slowly increase the circulating pressure to a maximum of 1500psi and condition the mud as required. 21. Tag TD, position liner at desired depth approximately 5ft off TD and slowly reciprocate while circulating to condition the hole. Recheck up and down weights. SETTING PROCEDURE 1.

Once circulation is complete, stop reciprocation.

2.

To hang the liner, inject the setting ball into the setting string and circulate slowly until the ball seats in the HSSR landing collar, slowly increase pressure to 1500psi. Hold pressure constant and slack off until the weight of the liner is resting on the hanger slips plus 10,000 lbs.

3.

Increase pressure on setting string to shear the ball seat in the landing collar. When this occurs the pressure will drop and circulation will be regained, correlate rates. (The QA/QC drawing will show the shear pressure required. A copy of this will be provided on the rig and to the shore based BDPS Engineer.)

4.

Resume circulation and establish that a circulation rate which will be required to cement the liner can be achieved.

RELEASE PROCEDURE 1.

Stop circulation.

2.

Slack off to shear pins in setting tool, standard 4 x 5/8" pins = 40,000 lbs.

3.

With 10,000 lbs on liner rotate setting string to release liner 20 turns. Rotate a further 10 turns to shoulder C clutch nut. When nut shoulders up a torque increase will be noted. Stop rotating and release torque.

4.

Pick up 3 to 4ft to note loss of liner weight (ensure pick-up distance is less than that required to expose the packer setting dogs to the PBR top). Record up and down weights. (If necessary, rotate setting string at 10, 15 and 20rpm and monitor torque; any necessary adjustments to the maximum allowable torque should be made at this time.)

To Rotate Liner 1.

Lower setting string until the C spline drive is engaged. Slack off until 5,000 lbs of setting string weight is applied to the liner top, establish circulation. Rotate string and liner, ensuring that you do not exceed the maximum rotating torque which has been previously calculated. If the liner will not rotate, stop circulation, pick up 1 to 2ft at the tool and rotate the drillpipe slowly, record the torque and adjust the maximum allowable torque as necessary per step 1.4.


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Test cement lines to company specifications. Mix and pump spacer. Commence cementing. After the cement has been pumped, release drillpipe pumpdown plug and commence displacement. Continue to rotate liner maintaining a continuous monitor or rotating torques and rpm. Slow down displacement 15bbls prior to plug latching. When plug latches, increase to 1600psi approximately and this will shear liner wiper plug.

3.

Resume displacement of liner until approximately 15 barrels before total displacement is pumped, slow pump rate down to 1 to 2bpm. Continue to displace until the liner wiper plug seats and latches into the landing collar. This will be indicated by rapid increase in pressure. Stop rotating 5bbls before plugs bump.

4.

Bump plug with 2500psi and hold for five minutes. Bleed off pressure and check for backflow.

5.

Pick up setting string 8 to 10ft, to enable packer setting dogs to be exposed to the PBR top, slack off 60,000 lbs to set type 'S' liner packer.

6.

Apply 500psi backpressure, pick up string. Make sure liner running tool is free. Note pressure loss. Pick up clear of liner top, reverse circulate if required, record cement returns.

7.

Pull out of hole with string, liner running tool and RPOB. Check same.


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PREPARATION AND RUNNING 7" ENACO/TIW ROTATING LINER HANGER WITH 'S' PACKER AND SJ-T MECHANICAL ROTATING TOOL FIGURE 1

A B

Size: 41/2" IF

Thread Up 41/2" IF Thread Down 41/2" IF

Tensile Load 959,000 lbs C

All Dimensions Shown in Inches

A 6.375 B 3.750 C 6.375 S. Morrison, June 1994, 01112262


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PREPARATION AND RUNNING 7" ENACO/TIW ROTATING LINER HANGER WITH 'S' PACKER AND SJ-T MECHANICAL ROTATING TOOL FIGURE 2

S.Morrison, Jul. 1994, 01112263

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PREPARATION AND RUNNING 4 1/2" NODECO ROTATING LINER HANGER WITH TSP PACKER




The TSP packer is run to avoid sole reliance on the cement in the liner lap. It is weight set and gives the advantage that the cement above the lap can be circulated out immediately that the cement job is completed. The preferred option is to run an integral packer with the liner.

1.3

When 4 1/2” casing is onboard, complete all general casing checks as per Sections 2000/GEN and 2900/GEN.

1.4


1.5

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe while POH to confirm DP tally. The liner running string must be drifted to a minimum of 2” (the OD of the metal body on the pump-down plug). A wireline retrievable dart/survey tool may be dropped as a drift. If the pipe is not drifted when POH, then it must be drifted when running the liner.

1.6


1.7

Ream once or twice through the hanger packer setting area with 6” bit.

2.


2.1

Nodeco MHR Liner Hanger with TSP Packer 1.

4 1/2” x 7” liner hanger assembly comprising: TSP liner packer with PBR. MHR multicone hydraulic rotating hanger. Length of PBR to be 10 ft.

2.

Liner hanger running tool assembly comprising: Shear-down junk bonnet. Type R running tool with RSM retrievable pack-off bushing. Slick cementing stinger (2 7/8” PAC pin up).

Note: It is normal for two complete assemblies of items 1 and 2 to be assembled and tested by the supplier and to be shipped to the rig in protective cradles.

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PREPARATION AND RUNNING 4 1/2" NODECO ROTATING LINER HANGER WITH TSP PACKER Plug dropping cement head and heavy duty swivel or top drive liner cementing system (see Figure 1): Flag sub (4 1/2” IF). Lift nipple (3 1/2” IF). 2 Nos. Plug holder adaptor. 2 Nos. “WLC” landing collar with shear-out ball seal and catcher. 2 Nos. Float collar. 2 Nos. Double valve float shoe. 2 Nos. Liner wiper plug. 2 Nos. Drill pipe pump down plug (OD of metal body 2”). 2 Nos. 1 1/2” setting ball. Radio-active marker, if required.

}


Note: a) Pup joints and a radio-active marker may be required. b) If shoe joints are assembled in town, slip-on centralisers should be installed at that time. 4. 2.2

Cement Kelly with drive bushings.

Liner Handling Equipment 2 Nos. 4 1/2” side door elevators. 2 Nos. 4 1/2” single joint elevators c/w swivel sling. 2 Nos. 4 1/2” rotary hand slips. (If non upset casing run then YC elevators and spider required.) 4 Nos. 4 1/2” klampon protectors. 2 Nos. Power tong dressed for 4 1/2” casing. 2 Nos. Hydraulic power unit for above. 2 Nos. Torque - turn units (if required). 6 Nos. Spare casing collars. 1 No. 4 1/2” casing spear c/w grapple/pack-off and stop ring. (Specify weight.) 4 1/2” springbow centralisers (as required). 4 1/2” stop collars (2 per centraliser). 1 No. 4 1/2” casing drift. API modified dope. Threadlock.

3.



2.

Dimension and part numbers of assemblies conform to those as per Figure 2 on Page 9 of this procedure. Measure all lengths and OD’s.

3.



Hanger pins: 4 Nos. brass screws (giving shear rating 1500 psi).

5.

Shear pins in ball seat of landing collar - 4 Nos. pins (shear rating 2800 psi).

6.

Packer shear pins: 2 Nos. (shear rating 11,000 lbs) plus 4 Nos. (shear rating 21,000 lbs).

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7.

Mark the tool and sleeve extension with paint to show if tool begins to back off at any time prior to running.

8.

Type 1 liner wiper plug is used. Check compatibility of the liner wiper plug with the weight of the 4 1/2” casing.

9.

Size and number of liner wiper plug shear pins. This information should be available in the documentation with an estimated shear pressure (normally +/- 1500 psi/4 screws).

10. Free passage of setting ball through the assembly including the Type 1 wiper plug. 11. Seating of the setting ball in the back-up landing collar ball seat. 12. Bore of PBR is compatible with outside diameter of compression set packer seal stem. 13. Free passage of pump down dart and setting ball by drifting all tools, i.e. kelly cocks, bumper subs, crossover subs, drillpipe, etc.

Note: On semi-submersible units the use of the cementing kelly eliminates the use of bumper subs under normal weather conditions. However, 2 bumper subs with 60” stroke may be required in adverse weather conditions. The minimum drift of the bumper subs is 2 1/2” for 7” liners and 2” for 5” and 4 1/2” liners. Ensure passage of the ball and dart through the bumper subs. 14. Pressure test plug dropping head and flag sub assembly against kelly cock to 5000 psi. 15. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the shoe and float collar. 16. Check the condition and rating of the cement manifold swivel to confirm that it is heavy duty. 17. Prior to running the liner, install the pump down dart in the cement manifold. Make up the cement manifold to the cement kelly and lay out the assembly on the pipe rack.

Note: Using the Nodeco cement Kelly, the lift sub is not backed out. 18. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. 19. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded. 20. On shallow or deviated wells, HWDP may be required to allow the TSP packer to be set with 31,000 lbs downward force. 4.



2.

Run the liner assembly as per Figure 2 on page 9 of this section. The shoe track is to consist of the following: Side Exit Shoe. 1 joint of 4 1/2” casing. Float collar. 2 joints of 4 1/2” casing. “WLC” landing collar c/w catcher and shear-out ball seat.

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PREPARATION AND RUNNING 4 1/2" NODECO ROTATING LINER HANGER WITH TSP PACKER Note: 4 1/2” liner is typically Range 3 (circa 9.5m long). Check the float equipment before RIH.

Notes: a) If drilling out of liner shoe is programmed, a side exit shoe with bakelite internals to be used. b) The distance between the landing collar and the float collar may be increased dependent upon advice from drilling office. All connections including casing collars to one joint above the landing collar to be threadlocked. 3.


4.


5.


6.


7.




Note: Bakerlok all connections on the first 4 joints. Bakerlok friction factor = 1.6. 9.


Note: a) Use the stabbing guide. b) Install pup joints and radio-active marker as indicated in the drilling programme. c) If a radio-active marker is installed, ensure that it is only handled by service company personnel. 10. Make up hanger/setting tool assembly complete with liner wiper plug onto liner. Ensure no rotation of tool and setting sleeve. Do not apply torque across the hanger assembly, i.e. tong only on hanger bottom or top subs. Ensure that the setting tool and all other connections are made up properly.

Note: a) Start threads using a chain tong. b) Leaving the slips on the liner joint, pick up 1m to check that the connection is correctly made up. 11. Circulate the contents of the liner assembly and record pressures at 2, 4 and 6 BPM to determine the approximate liner ECD in the 7” liner. Pressure is not to exceed 500 psi. Visually check hanger for leaks and record pressures at various circulation rates up to 250 gpm. 12. Note weight of full liner on Martin Decker.

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13. Check hanger for any damage. Check the shear pin on the split junk bonnet. Lower hanger assembly through rotary and set DP slips on the 3 1/2” lift nipple - do not set slips on the setting sleeve. Be careful to keep the hanger centred while lowering through the table to avoid damage to the piston, slips, etc. 14. RIH on 3 1/2”/5” DP. Ensure the first 15 stands of pipe has protectors removed (to reduce the chance of cementing up the string and to allow the facility to washover if required). RIH filling every stand. Drift every stand to 2” minimum. Use the drillpipe wiper rubber and ensure string does not turn in the table.

Note: a) Do not exceed calculated running speeds. b) Always use a back-up tong when running the complete liner assembly. c) Exercise caution entering 7” liner lap. 15. Check up and down drags at the 7” casing shoe. Break circulation but do not exceed 1000 psi surface pressure. Ensure top drive swivel or cement head and cement lines made up before going into open hole. 16. Continue RIH. Lock the elevators and pick up cement head or top drive swivel. Ensure running string is spaced out such that with the liner shoe 2m off bottom, there is enough overstand to set the liner on bottom if necessary. Drift all pup joints and singles picked up from the pipe deck.

Note: The Type R Running Tool and MHR Hydraulic Rotating Liner Hanger assembly allow the liner to be rotated while washing down through bridges in open hole as long as the brass shear pin in the split junk bonnet in the PBR top remains intact. The shear screw is sheared out only if the liner weight is lost and force is applied to the liner top. This could occur either if a) the entire weight of the liner is lost due to a bridge whilst washing down, or b) by catching an upset on the hanger assembly (slips, cylinder, etc.) on the BOP stack, wellhead or other obstruction. To prevent shearing the pin, beware when running the liner assembly through the BOP and wellhead and limit slack-off weight when washing down through bridges to 80% of the liner weight. If the junk bonnet pin is sheared prematurely, rotation should not be applied until the hanger has been set. 17. Check string weight and up/down drags. 18. Wash down (with the compensator open on floating units), rotating only if necessary. Do not exceed 1000 psi. Rig up cementing lines and test to 5000 psi against the cement head.

Note: Use sufficient Chiksan swings to allow for tailpipe pick-up clear of the PBR. 19. Break circulation by staging up pressure in 500 psi increments every 5 minutes. Wash and tag bottom with liner, mark the pipe and pull back 2m. Circulate bottoms up + 20% or 120% string volume whichever is the greater. In high temperature wells, extended circulation may be required. Do not exceed 1000 psi initially. Slowly increase the circulating pressure to a maximum of 1500 psi and condition the mud as required. Limit flow past TSP to 6 bpm.

Note: 1500 psi internal pressure will set the liner if circulation is not achieved. 20. Check string weight, with and without circulation and record circulating pressures. To prevent packing off, do not move the liner without circulating and do not slack off more than 80% of the liner weight.

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PREPARATION AND RUNNING 4 1/2" NODECO ROTATING LINER HANGER WITH TSP PACKER Note: Do not exceed the maximum ECD achieved when drilling the 6” hole.

5.


Drop the setting ball through the ball launcher in the plug launching head. Allow time for the ball to seat in the landing collar/shear out sub. Setting ball may be pumped down at a flowrate of 3 bbl/min. Limit pressure to 700 psi. During this time check the pick-up and slack-off weights, tag bottom and pick up to the liner setting depth.

Note: a) The ball should take approximately 2 - 3 minutes per 300m to land on its seat. b) Standard 4 1/2” MHR hanger, 4 screws = 1500 psi shear. 2.

When the ball lands pressure up in stages to 1700 psi to set the hanger.

3.


When hanger has set, set down +/- 15000 lbs DP weight, mark the pipe and shear ball and seat at a pressure of +/- 2800 psi. Shear-out is indicated by the ability to circulate at a similar rate and pressure as noted prior to dropping the ball.

b)


4.


5.

Pick up to 15,000 lbs less than the theoretical running string weight. Rotate the running string 6 turns to the right. Note the rotary torque and check for residual torque.

6.

Pick up the running string weight plus 0.5m (use the compensator on Floating Rigs) to ensure that the tool is released.

Note: a) Pick-up must not exceed half the distance from the packer actuator to the top of the PBR or half the distance from the pick-up sub to the retrievable pack-off bushing, whichever is less. b) Confirm that the pick-up weight is minus the weight of the liner. Note: As the allowable distance of travel with the standard running tool and PBR is very small, pulling any substantial distance will engage the packer setting dogs in the setting profile and result in premature setting of the packer and preclude cementing of the liner. When running the liner in deeper high angle wells, controlling the movement of the string over such small distances is impractical, even the inaccuracy of establishing the neutral point for release can, at these depths, leave stretch in the string which could potentially engage the packer setting dogs. Consideration must therefore be given to the following: a)


b)


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PREPARATION AND RUNNING 4 1/2" NODECO ROTATING LINER HANGER WITH TSP PACKER Prior to cementing, set down 15,000 lbs weight on the hanger.

Note: Set down weight is dependent upon the pump-out forces when shearing out and bumping the liner wiper plug. This shear-out force increases considerably if inverted cups are used instead of the retrievable pack-off bushing (Nodeco do not normally supply swab cups). 8.

Break circulation and commence right hand rotation. 2-3 turns will transmit torque to the liner. Limit torque total to (cased hole torque + liner thread torque x 80%). Establish rotation of liner at 15-20 rpm. Only rotate the liner when circulating. If rotation is not practical continue with cement operation.

Note: Do not exceed the maximum ECD achieved during drilling the 6” hole. 9.


10. After checking for backflow following the cement job, set the TSP packer by picking up the running tool 3m at the liner top. This will place the packer setting dogs above the tie-back extension which is 3.4m long (dependent on PBR length). 11. Slack off and set weight down to set the TSP packer. Approximately 16,000 lbs will shear the first set of pins and allow the packer to begin setting. Increasing the set down weight to 31,000 lbs will shear the second set of pins and force the packer hold-down slips against the 7” casing. 12. Pump 5 bbl to lift cement whilst rigging up. Reverse circulate out the excess cement and spacer after pulling the stinger to just above the PBR. Avoid running into the PBR.

Note: Do not carry out casing test at this point, the liner lap will be tested on the cleanout trip. 13. On deviated wells, reciprocate the string to ensure any low side cement is circulated out. 14. Monitor for contaminated cement returns (if OBM is in use refer to Section 3780/GEN). Pull out of hole with the running tool. Ensure hole is kept full. Monitor fill volume.


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PREPARATION AND RUNNING 4 1/2" NODECO ROTATING LINER HANGER WITH TSP PACKER FIGURE 1 TOP DRIVE CONNECTION

BAILS


ELEVATOR


SETTING BALL

3" WECO CONNECTION




SAFETY LINE/CHAIN




911208/15

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BP EXPLORATION


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PREPARATION AND RUNNING 5" BAKER HMC LINER HANGER WITH CPH PACKER



If calculations indicate loadings are within 15 percent of casing design loads, alternative hanger designs may have to be considered. It is possible that single cone hanger equipment will not satisfy casing loading criteria. Multi cone equipment should be the first choice when selecting hanger equipment.

Note: The HSR hanger is a single line hanger. 1.2


1.3

When 5” liner is onboard, complete all general casing checks as per Sections 2000/GEN and 2900/GEN.

1.4


1.5


Note: The maximum allowable surface torque is 80% of this value. 1.6

It is essential that TD is confirmed accurately prior to running the liner. Strap the pipe while POH to confirm DP tally. The liner running string must be drifted to 2”. A wireline retrievable dart/survey tool may be dropped as a drift. If the pipe is not drifted when POH, then it must be drifted when running the liner.

1.7


2.


2.1

Baker (Brown) Rotating Liner Hanger Equipment 1.

5” x 7” HSR rotating liner hanger assembly comprising: 5” LS sleeve with PBR extension. Profile nipple with RS profile. HSR rotating hanger. Length of PBR to be 6 ft for vertical wells and 15 ft for deep or deviated wells.

2.

Rotating liner hanger running tool assembly comprising:

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:

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PREPARATION AND RUNNING 5" BAKER HMC LINER HANGER WITH CPH PACKER Shear-out junk bonnet assembly. 2 RH rotating setting tool with retrievable or drillable pack-off bushing. Slick tailpipe assembly with swivel and type 1 liner wiper plug.

Note: It is normal for two complete assemblies of items 1 and 2 to be assembled and tested by the supplier and shipped to the rig in protective cradles. 3.

Plug dropping cement head and heavy duty swivel or top drive liner cementing system (see Figure 1): Flag sub (4 1/2” IF). Lift nipple (4 1/2” IF). 2 Nos. Float collar with baffle plate. 2 Nos. Type 2 landing collar with shear-out sleeve. 2 Nos. Type V set or side exit shoe. 2 Nos. Drill pipe pump down plug. 2 Nos. 1 1/2” setting ball.

}


Note: a) The liner hanger utilises premium connections throughout. b) Pup joints and a radio-active marker may be required. c) If standard float collar is supplied by BP, then a catcher sub will be required. 4. 2.2



3.



2.


3.


Note: On occasions a longer PBR may be supplied.

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4.

Hanger pins: 2 Nos. 5/16” pins (shear rating 1400 psi).

5.


6.


7.


8.


9.


10. Free passage of setting ball through the assembly including the Type 1 wiper plug. 11. Seating of the setting ball in the landing collar shear out sleeve. 12. Bore of PBR is compatible with outside diameter of compression set packer seal stem. 13. Free passage of pump down dart and setting ball through all tools, i.e. kelly cocks, bumper subs, crossover subs, drillpipe, etc.

Note: On semi-submersible units the use of the cementing kelly eliminates the use of bumper subs under normal weather conditions. However, 2 bumper subs with 60” stroke may be required in adverse weather conditions. The minimum drift of the bumper subs is 2 1/2” for 7” liners and 2” for 5” and 4 1/2” liners. Ensure passage of the ball and dart through the bumper subs. 14. Pressure test plug dropping head and flag sub assembly against kelly cock to 5000 psi. 15. Shoe track equipment to be checked thoroughly. Ensure that the valves are free in the “V” shoe and float collar. 16. Check the condition and rating of the cement manifold swivel to confirm that it is heavy duty. 17. Prior to running the liner, install the pump down dart in the cement manifold and torque the lift sub to 12,000 ft/lbs. Mark the body and lift sub with white paint to indicate backing out. Make up the cement manifold to the cement kelly and lay out the assembly on the pipe rack. 18. Prepare a graph of joints run versus hookload. Use this to check that the casing is being filled correctly. 19. Calculate swab/surge pressures at various running speeds and select an acceptable running speed to ensure that the formation breakdown pressure is not exceeded. 4.

RUN 5” LINER 1.

A type CPH hydraulic set packer will be run on top of the 5” liner hanger. This packer will perform two main functions: a)

Act as a seal (if cement fails) in the 5”/7” overlap.

b)

Resist upward differential pressure forces acting on the bottom of the 5” liner.

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2.

Drift all liner components (drift ID 18 lb/ft = 4.151”), remove protectors, clean and inspect threads for damage. Measure and tally liner. Fit centralisers to the liner on the piperack. Carry out all general instructions as per Sections 2000/GEN and 2900/GEN.

3.

One Weatherford ST ISL Bow Type Centraliser per joint along complete liner length. Note: These centralisers must be the type that use grub screws to hold in position. Therefore, no 5” stop collars are required.

4.

Make up 3 1/2” drillpipe to liner hanger/running tool and stand back in derrick. (Drift both 3 1/2” and 5” drillpipe to 2”.) Drift 3 1/2” dp before making up to running tool.

5.

Make up liner as follows: a) Baker type V set shoe. b) One joint of 5” liner. c) Float collar c/w baffle. d) One joint of 5” liner. e) Baker type II landing collar w/shear out seat. f) 5” liner with centralisers (install a short joint for depth correlation). g) 5” liner hanger, type HMC. h) Type CPH packer. i) PBR (standard length is 10 ft with the CPH packer). j) Liner running tool. Type of pack-off. Note: PBR preferred. k) 3 1/2”/5” drillpipe to surface (ensure dart sub is not in string). Do not use HWDP.

Note: Items g), h) and i) are made up and pressure tested onshore. Bakerlok up to and including the landing collar. 6.

Circulating pressure must not exceed 600 psi at any time prior to setting the hanger.

7.

Make up hanger assembly and break circulation. Continue running on drillpipe. Partially fill every stand, and fill completely every five stands.

8.

Exercise extreme caution whilst hanger and packer are passing DV collar and entering 7” PBR. Fill drillpipe every five stands, ensuring that no air is trapped in the string. Fill completely and circulate liner and string contents before entering open hole. Check surge pressures/running speed across reservoir. Drift all drillpipe using one 2” diameter drift.

9.

Run liner to bottom. Hanger to be positioned inside 7” liner as per Drilling Programme.

10. Reciprocate liner and circulate out liner and drillpipe contents. 11. Set liner shoe +/- 1m off bottom. Drop setting ball and pressure up to 1,500 psi to set hanger. Shear out the ball and seat with 2,500 psi. 12. Pick up to 15,000 lbs less than the theoretical running string weight. Rotate the running string 10 turns to the right. The hanger should release after 6 turns. Note the torque.

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13. Pick up the running string weight plus 0.5m to ensure that the tool is released.

Note: a) Pick up must be less than the length of the tailpipe below the hanger. b) Packer setting dogs must not come past top of tie-back extension when usibng an RS packoff. c) When using an RS retrievable pack-off the running tool cannot be re-engaged. Note: A PBR type pack-off is the preferred option. As the allowable distance of travel with the standard running tool and standard length PBR is very small, pulling any substantial distance will engage the packer setting dogs in the setting profile and result in premature setting of the packer and preclude cementing of the liner. When running the liner in deeper high angle wells, controlling the movement of the string over such small distances is impractical, even the inaccuracy of establishing the neutral point for release can, at these depths, leave stretch in the string which could potentially engage the packer setting dogs. Consideration must therefore be given to the following: a)


b)


14. Prior to cementing, set down 20,000 lbs weight on the hanger.

Note: Set down weight is dependent upon the pump open forces when shearing out and bumping the plug. The shear-out force increases considerably if inverted cups are used instead of a pack-off bushing (Note: swab cups are not recommended). 15. Establish circulation and cement as per Section 3500/GEN.

Note: Do not exceed the maximum ECD achieved during drilling the 6” hole. 16. After checking for backflow following the cement job, set the CPH packer by picking up the running tool to place the packer setting dogs above the CPH packer tie-back extension (minimum 10 ft for a standard PBR). Maintain 500 psi on the running string as the tailpipe is pulled to give an indication of being free. (This also gives a hydraulic advantage if a PBR type pack-off is used.) 17. Rotate the running string 6-10 turns to the right to ensure that the tool is free. Pick up on the running string but do not pull above the previous up stroke weight before the liner was set. If pickup weight exceeds the previous value, set down 20,000 lbs on the liner and put in additional righthand turns while observing rotary torque. If this does not work then the tool is stuck in the liner or cement.

Note: The pipe may be worked to 80% of pipe yield strength when the top drive swivel head is in use. 18. Pull the running tool above the CPH packer tie-back extension, then move the tool down until weight is taken on the packer top. 13 - 17,000 lbs down will shear the first pins and start to set the packer. 40,000 lbs down will shear the second set of pins and force the packer hold-down slips against the 7” casing.

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19. Reverse circulate out the excess cement and spacer after pulling the stinger to just above the PBR. Avoid running into the PBR. On deviated wells, reciprocate pipe to ensure no cement is left on the low side which could cause pipe to stick.

Note: Do not carry out casing test at this point, the liner lap will be tested on the cleanout trip. 20. Once the excess cement is out of the wellbore, pull out.

Note: Rotate and reciprocate the running string whilst circulating it clean. Monitor for contaminated cement returns (if OBM is in use, refer to Section 3780/GEN). 21. Pull out of hole with the running tool.


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PREPARATION AND RUNNING 5" BAKER HMC LINER HANGER WITH CPH PACKER FIGURE 1 TOP DRIVE CONNECTION

BAILS


ELEVATOR


SETTING BALL

3" WECO CONNECTION




SAFETY LINE/CHAIN




911208/15

BP EXPLORATION


Section

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2560/GEN

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:

3 (10/91)

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BP EXPLORATION


Section

:

2600/GEN

Rev.

:

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1 of 2

EXTERNAL CASING PATCH OPERATIONS

A casing patch may be required because of: a)

Leaks have developed in a casing string.

b)

Casing must be cemented before a casing hanger has landed and well control requirements prevents installation of an emergency slip and seal.

1.1

If the casing must be cemented, ensure the top of the cement column is such that it allows casing stretch and gives the casing support required when the casing is cut prior to patching.

1.2

Whilst waiting on cement, review: 1.

The free casing weight and if: a)

Casing can be cut below the rotary table and left free standing.

b)

The casing must be supported after cutting.

c)

How returns will be obtained when casing cutter is run.

2.

The position of casing centralisers relative to proposed cutting depth.

3.

The casing joint lengths.

4.

Calculate patch running string lengths. Ensure mid-patch depth approximates to the centre of a casing joint.

1.3

If casing extends through the rotary table: Either:

1.4

a)

Cut the casing below the rotary with the welder.

b)

Back out the upper joints of casing.

c)

If a power swivel or mud motor is available to drive the casing cutter proceed as per 1.4.

Run casing cutter and cut the casing. If the casing above the cutter is unsupported, when cutting the string may torque up. Stop the pump, restart the rotary, ensure free rotation. Restart the pump and continue cutting.

Note: Ensure magnets are in place after the shaker screens and viscous slugs are used to sweep the hole. 1.5

When cutting is completed, run a spear, pull and lay out casing. Caliper the casing stub of the retrieved casing to ensure that the OD of the cut in the remaining casing is accurately known. Run a mill to dress the top of the stub. This mill is intended to remove burrs and chamfer or round both the inside and outside of the stubs end face. If a casing hanger is to be used confirm the patch to hanger lengths. Check the wear profile on the mill to confirm stub is correctly finished.

1.6

Make a dummy run with a patch minus the internal grapple and seal sections to confirm it is possible to engage the casing stub. If difficulty is experienced getting the patch over the casing stub, it may necessary in extreme cases to run an interal guide string. a)

Set patch and landing string in the rotary.

b)

Make up and run a stabiliser through the running string.

BP EXPLORATION


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:

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EXTERNAL CASING PATCH OPERATIONS

Use a slotted plate and two elevators. c)

Space out the stabiliser string such that it extends below the patch.

d)

Arrange to pick up the patch running string and the guide string together.

e)

The stabiliser should enter the casing stub and guide the patch over the stub as the string is lowered.

1.7

Make up the patch complete with seals and grapples and run in hole. If no difficulty stabbing the dummy patch, install a circulating head on the running string.

1.8

Land the patch with the pump running. Entry of seals into the stub will be indicated by a pressure rise. When the pressure rise is seen, shut off the pumps and open a side outlet on the circulating head to atmosphere. This will prevent a pressure build up which could support the patch running string weight. If hanger is used land hanger.

1.9

When the patch is over the stub pull the ± 30,000 lbs overpull to check the grapple has latched. Pressure test the patch. The test pressure will depend upon patch and seal type and will be advised by the drilling office. Re-land the hanger if hanger is used. If a slip and seal assembly is to be installed pull to required value and install seal assembly.

1.10

1.11

If hangers are used it will be necessary to: a)

Run a spear through the landing string and patch.

b)

Latch the casing c. 5m below the top of the casing stub.

c)

Pull the required overpull on the casing stub to support the free casing weight in air, plus an extra allowance for patch slip movement. Ensure the landing string does not lift.

d)

Pull the spear.

Pressure test the patch as advised by the drilling office.

BP EXPLORATION


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:

2700/GEN

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:

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CONNECTORS: HUNTING MERLIN

THE MERLIN CONNECTOR The MERLIN connector, developed by Hunting Oilfield Services Limited, has been created for the rapid assembly of casing and conductors. Well proven since its introduction in 1984, the MERLIN has demonstrated its rapid make-up and separation capabilities on platform, jack-up and semi-submersible rig operations. The MERLIN connector has been subjected to a comprehensive range of full scale testing, including tension, compression, bending, pressure, pile driving and fatigue bending, plus many combined load tests. The connector's radial preload gives a high degree of resistance to rotation, and coupled with the connector's optimised geometry, it ensures good fatigue resistance. END PROTECTORS To avoid damage during transit and storage, the MERLIN connector is fitted with composite end protectors. The protectors consist of a fabricated steel can with bonded elastomeric compound to protect the MERLIN nose seal. The protectors are held on by several bolts which are fitted with anti-rotation washers to ensure they do vibrate loose in transit.

PERFORMANCE PROPERTIES

Loading Capabilities

30" Merlin-D I.F.

27" Merlin-D

20" Merlin E.F.

20" Merlin I.F.

Tension

3.5 x 106 lbf

3.3 x 106 lbf

2.2 x 106 lbf

2.0 x 106 lbf

Compression

4.0 x 106 lbf

-

-

-

Bending

2.6 x 106 lbf.ft

2.2 x 106 lbf.ft

1.01 x 106 lbf.ft

0.92 x 106 lbf.ft

Internal Pressure

3,000 psi

3,500 psi

4,000 psi

4,000 psi

Outside Diameter

31.500"

28"

20.00"

22.250"

Inside Diameter

28.000"

24.32"

16.500"

18.750"

Length

15.100"

15.10"

15.100"

15.100"

Weight

630 lbs

565 lbs

300 lbs

300 lbs

Material Yield

-

100 ksi

100 ksi

100 ksi

G.A. Drawing No.

HDP/2152/A3

HDP/2296/A4

HDP/2514/A3

HDP/1622/A3

Dimensions

11.5" ( 292 )

PROTECTOR GROOVE

OIL INJECTION PORT

15.1" ( 384 )

CLAMP GROOVE

Rev.

Section

:

:

1 (12/89)

2700/GEN

2179/123

2 of 11

LANDING SHOULDER

:

DIA 20" ( 508 ) DIA 22.07" ( 561 )

Page

'O' RING METAL / METAL SEAL

PIN PART No :- MPOO8

BP EXPLORATION

BOX PART No :- MBOO8

METAL / METAL SEAL

DRILLING MANUAL

CLAMP GROOVE


11.5" ( 292 )

SUBJECT:

DIA 22.25" ( 565 ) DIA 18.75" ( 476 )

NOTE : ALL DIMENSIONS IN BRACKETS ARE IN MILLIMETRES

SUBJECT:

NOTE : ALL DIMENSIONS IN BRACKETS ARE IN MILLIMETRES

OIL INJECTION PORT

15.1" ( 384 ) 11.5" ( 292 ) METAL / METAL SEAL BLEED PORT CLAMP GROOVE

Rev.

Section

:

:

:

3 of 11

1 (12/89)

2700/GEN

2179/122

Ø18.00" ( 547 )

Page

Ø16.50" ( 419 )

BP EXPLORATION

11.5" ( 292 )

DRILLING MANUAL

PRESSURE RELIEF PORT METAL / METAL SEAL

20" x 1.0" W.T. MERLIN E.F. GENERAL ARRANGEMENT

CLAMP GROOVE


Ø20.00" ( 500 )

SUBJECT:

Ø707

BOX CLAMP GROOVE RELIEF PORT ( PLUGGED ) METAL / METAL SEAL

292

OIL INJECTION PORT

384

292

Section

:

:

1 (12/89)

2700/GEN

2179/121

Rev.

PIN

4 of 11

Ø711

:

METAL / METAL SEAL CLAMP GROOVE

Page

BLEED PORT ( PLUGGED )

BP EXPLORATION

Ø610

DRILLING MANUAL

Ø622 ( 24.5" )


Ø686 ( 27.0" )

SUBJECT:

15.350"

'O' RING METAL / METAL SEAL CLAMP GROOVE LANDING SHOULDER ( OPTIONAL ) PIN

Rev.

Section

:

:

:

5 of 11

1 (12/89)

2700/GEN

2179/120

Page

28" DIA 30" DIA 31.5" DIA

BP EXPLORATION

METAL / METAL SEAL

DRILLING MANUAL

CLAMP GROOVE


BOX

BP EXPLORATION


Section

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2700/GEN

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6 of 11


Assembly The illustration shows the sequence of assembly of the MERLIN connector. In summary, the sequence is: 1)

Remove the protectors.

2)

Clean and inspect the connector components.

3)

Stab the box over the pin to the "stand-off" position.

4)

Fit the clamp over the connector.

5)

Fit the injector nozzle.

6)

Apply pressure to the clamp and injector, via the power pack, until the connector is assembled.

7)

Check the abutment face for complete make-up.

8)

Remove the clamp and the injector nozzle.

9)

Plug the injection port, bleed port and pressure relief port.

Separation Process The illustration shows the sequence of separation of the MERLIN connector. In summary, the sequence is: 1)

Remove the injection port plug and ensure the bleed and relief port plugs are in place.

2)

Fit the clamp around the connector.

3)

Fit the injector nozzle.

4)

Pressurise the clamp and injector until the connector "jumps" apart. Continue until the connector is fully separated.

5)

Remove the clamp and injector nozzle.

6)

Lift the box off the pin.

7)

Clean the components and regrease.

8)

Fit the protectors.

BP EXPLORATION


Section

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2700/GEN

Rev.

:

1 (12/89)

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7 of 11


The Merlin Clamp and Powerpack There are only two major pieces of equipment required to run MERLIN connectors, namely the MERLIN clamp and powerpack. The clamp is utilised for both make-up and separation, one procedure being the reverse of the other. The clamp consists of three segmented rings, the top and bottom rings are fixed and the middle ring slides up and down the tie rods, driven by the 20 ton rams. The top ring carries the rams and tie rods which are also secured in the bottom ring which locates in the clamp groove on the MERLIN pin. The moving middle ring locates in the clamp groove on the MERLIN box. The rings open to engage around the connector and are closed by hand toggles, this is a two man operation. The interface fluid INTERTEC is supplied at pressure via the injector from the powerpack and works in parallel with the rams, at a downward stroke of the rams the MERLIN connector is made-up and with an upward stroke the MERLIN connector is separated. The clamp can be supported by a rig air hoist and has a simple built-in levelling device and height adjusting cylinder. Incorporated in the clamp are closing levers which assist opening and closing of the clamp by acting against the casing. Both the clamp and powerpack are situated on the drill floor during operation, the powerpack requiring only rig air for operation. All controls for the clamp operation are situated on a control panel mounted on the clamp.

BP EXPLORATION


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2700/GEN

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8 of 11

CONNECTORS: HUNTING MERLIN MERLIN CONNECTOR SEPARATION PROCESS

BOX

PIN

SEPARATION

CLAMP

INJECTOR CLAMP

/ " ABUTMENT GAP

1 2

INJECTOR

MADE-UP

2179/119

BP EXPLORATION


Section

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2700/GEN

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:

1 (12/89)

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9 of 11


MERLIN CONNECTOR ASSEMBLY PROCESS

INJECTOR

MAKE-UP

CLAMP

INJECTOR

CLAMP

/ " ABUTMENT GAP

12

BOX

PIN

STAND-OFF

2179/118

BP EXPLORATION


Section

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MERLIN CLAMP HINGE (2 POSITIONS) OPENING TOGGLES

CONTROL PANEL

COUNTER WEIGHT HEIGHT ADJUSTMENT

GUARD

LIFTING ARM 20 TON RAM TOP RING MIDDLE RING BOTTOM RING

2179 / 117

BP EXPLORATION


Section

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2700/GEN

Rev.

:

1 (12/89)

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11 of 11

CONNECTORS: HUNTING MERLIN UNIVERSAL POWERPACK

STAINLESS STEEL ROLLER DOOR CONTROL PANEL

INJECTION PUMP

AIR MOTOR

ACCUMULATOR

HYDRAULIC RADIAL PUMP

HYDRAULIC TANK

OVERALL DIMENSIONS LENGTH WIDTH HEIGHT WEIGHT

:- 50" (1270mm) :- 50" (1270mm) :- 70" (1778 mm) :- 2090 lbs (950kg)

AIR SUPPLY (MINIMUM) 100 psi (7 Bar) 150 CFM (4250 L/Min)

2179 /116

BP EXPLORATION


Section

:

2705/GEN

Rev.

:

2 (1/94)

Page

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1 of 10

CONNECTORS: HUNTING LYNX

There are two versions of the Lynx connector in current use in BP operations, the standard duty Lynx SA which is generally on 1" wall 30" pipe, and the heavy duty HD on 1 1/2" wall 30" pipe. Versions used in the past, such as the Lynx 52/BP Magnus Lynx, may appear similar, but there are significant technical differences. The SA and HD connectors have the following features in common: •

Internal flush, weight-set connector.

•

Integral anti-rotation blocks may be fitted if required.

•

Can be used in pile driving applications, and is fully re-usable.

•

Easy and quick make-up and disconnection of connector without requirement for special tools.

•

Visual proof of make-up on external split lock ring.

•

Design prevents build-up of sea debris in the jacking mechanism or on the mating faces.

Further details of each connector, including the procedures for their make-up, running and retrieval, are provided in the subsequent sections.

1.

LYNX SA The general arrangement of this connector is illustrated in Figure 1. The technical data for the SA connector is as follows: Tension

1.1

:

3.2 x 106 lbf 106

lbf.ft

(14.2 MN)

Bending

:

2.8 x

(3.8 MNm)

Pressure

:

1,500 psi

(10.3 MPa)

Torque (when anti-rotation block is fitted)

:

30,000 ft.lbs

(40.7 kNm)

Material Yield Minimum

:

100,000 psi

(689.5 MN/mm2)

Preparation on Pipe Deck Remove pin protectors (there are no box/lock ring protectors). Thoroughly clean pin, box and lock ring, ensuring that both the lip seal and the "O" ring are fitted and seated correctly. Section 3 and Figure 7 provide details on the correct fitting of the lip seal. If anti-rotation is a requirement, ensure an anti-rotation block is fitted within each box connector. With paint or indelible marker, mark a vertical line on the exterior of the pipe at the location of the cut-out in the pin component, and the anti-rotation device in the box on the external pipe body. Lightly coat the surface of each component with clean grease or oil. Replace pin protectors.

1.2

Make-Up Procedure Remove protectors, and ensure all jack screws are removed from the lock ring. If anti-rotation blocks are fitted, ensure the external location marks are vertically lined up on the pin and box before and during stabbing.

BP EXPLORATION


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2705/GEN

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2 of 10


Stab the box and lock ring over the pin, allowing the weight of the joint to bear on the connector, which will force the snap ring to be expanded, then to snap back over the pin connection, thus engaging the connector. Measure and check dimension of gap on closed lock ring to ensure full engagement. As indicated on Figure 2, the correct dimension is 0.75" with a tolerance of +0.25" or -0.125". If the gap is outwith this range, DO NOT RUN THE JOINT. Figure 3 provides guidance on carrying out additional checks to ensure full make-up of connector. Fill screw holes with seawater resistant grease.

Note: If the joint to be added on is too short for its weight to allow the connection to make up with the above procedure, the following procedure should be used:

1.3

•

Insert all seven jack bolts.

•

Using a wrench fitted with a 36 mm AF socket, tighten the seven M24 jack bolts until they shoulder out. NOTE that they MUST be tightened in order, starting with the bolt diametrically opposite the split in the lock ring, then screwing alternate sides towards the split. This sequence is illustrated in Figure 4.

•

Engage the connection.

•

Relax the split ring by releasing, in reverse order, the seven jacking bolts.

•

Check for full engagement as detailed in the section above.

•

Fill screw holes with seawater resistant grease.

Retrieval Procedure Using the wrench and 36 mm AF socket, screw in each of the supplied seven M24 jacking screws until they shoulder out. As indicated in Figure 4, start with the screw directly opposite the split, and screw alternate sides, working towards the split. Lift the joint free. Remove the jacking screws in reverse order to allow the lock ring to return to its relaxed position. Clean both pin and box/lock ring, and coat with clean grease or oil. Fit protector to pin connection.

2.

LYNX HD This is a heavy duty connector usually fitted to conductor of 1 1/2" wall thickness. The general arrangement is illustrated in Figure 5. Note that, as opposed to the SA connector, the seven jacking bolts on the HD connector are of size M30, requiring a 46 mm AF socket wrench, and are positioned on the flank of the lock ring, as opposed to being on the upper shoulder on the SA connector. The technical data for the HD connector is as follows: Tension

: 6.97 x 106 lbf 106

lbf.ft

(31 MN)

Bending

: 4.55 x

(6.2 MNm)

Pressure

: 1,500 psi

(10.3 MPa)

Material Yield Minimum

: 100,000 psi (minimum)

(689 N/mm2)

BP EXPLORATION


Section

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2705/GEN

Rev.

:

2 (1/94)

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3 of 10


Preparation on Pipe Deck The procedures to be followed are as per those for the SA connectors as provided in Section 1.1 above.

2.2

Make-Up Procedure The make-up procedures are as per those for the SA connectors as provided in Section 1.2 above. The following notes will confirm certain relevant features:

2.3

1.

The gap in the lock ring when fully engaged is identical to that of the SA connector - 0.75", with the same tolerance figures (see Figure 2).

2.

Although identical to that for the SA connector, Figure 6 illustrates the sequential order of inserting the seven jacking bolts.

Retrieval Procedure Again, the SA retrieval procedures in Section 1.3 are to be followed, substituting Figure 6 where appropriate. However, after expanding the lock ring by inserting all seven jacking bolts, and before separating the two halves of the connector, the three safety bolts must be inserted on the upper edge of the lock ring as indicated on Figure 6. This is to ensure the lock ring remains with the box connection during the separation process.

3.

PROCEDURE FOR FITTING LYNX LIP SEAL

3.1

Thoroughly clean the lip seal groove with a degreasing agent, ensuring that the groove is free from all foreign matter.

3.2

Apply a light coating of Molycote 33 Medium grease (or similar) over the full surface area of the lip seal.

3.3

Initially position the lip seal in the groove (see Sketches 1.1, 1.2) and locate in four diametrically opposite positions, ensuring that the body of the lip seal is fully seated each time.

3.4

The remaining lengths should then be pushed into position starting from one of the four original points and working in a clockwise/anti-clockwise direction, ensuring that the body is properly seated around the full diameter. During this stage the tendency to slide the fingers around the seal should be avoided, as this can cause stretching, leaving an excess amount at the end. If this occurs, the lip seal should be removed and re-fitted.

3.5

The final operation should be to ensure that the nose of the lip seal is proud of the groove (see Figure 7). This can be achieved by lifting the nose up, with the fingers, and sliding around the diameter.

SUBJECT:

ANTI-ROTATION BLOCK ( OPTIONAL )

12.031" ( 306 )

LIP SEAL 'O' RING LOCK RING LANDING SHOULDER PIN

Rev.

Section

:

:

4 of 10

2 (1/94)

2705/GEN

Figure 1

2179/112

:

NOTE: DIMENSIONS IN BRACKETS ARE IN MILLIMETRES

Page

Ø28.000" ( 711 )

BP EXPLORATION

7 off M24 JACKING BOLT HOLES

DRILLING MANUAL

BOX

30" LYNX S.A. GENERAL ARRANGEMENT

Ø30.000" ( 762 )


Ø33.500" ( 851 )

BP EXPLORATION


Section

:

2705/GEN

Rev.

:

2 (1/94)

Page

:

5 of 10

CONNECTORS: HUNTING LYNX Figure 2

30" Lynx S.A. Connector Detail of Lockring Gap with Acceptable Width Dimensions when Properly Made-Up

+0.250"

0.75" -0.125"

S.Morrison, Dec. 1993, 01110053

BP EXPLORATION


Section

:

2705/GEN

Rev.

:

2 (1/94)

Page

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6 of 10


30" Lynx S.A. Connector

Note: When correctly assembled, lock ring gaps and shoulders will be uniform around circumference.

ADDITIONAL INDICATIONS OF FULL MAKE-UP

BP EXPLORATION


Section

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2705/GEN

Rev.

:

2 (1/94)

Page

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7 of 10


30" Lynx S.A. Jacking Screws (7 off)

Lip Seal 'O' Ring

Jacking Bolts Screwed in Hand Tight 1 2

3

4

5

6

Sequence of Screwing in Jacking Screws for:Make-Up (1-7) & Separation (7-1)

7

Jacking Bolts Screwed Fully in

Box/Lockring Lifted Away S.Morrison, Dec. 1993, 01110052

BP EXPLORATION

DRILLING MANUAL

:

2705/GEN

Rev.

:

2 (1/94)

Page

:

8 of 10


Pin

Landing Shoulder

Lip Seal

'O' Ring Seal

Jacking Bolt Hole

Box

Lockring

General Arrangement - Lynx HD

8.500"

,,,,,,,,,,,,, ,,,,,,,,,,,,,

34.100"

30.950"

30.000" 9.700" 15.380"

7 off Jacking Bolt Holes, M30

30.000"

27.000"

8.500"

,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,, ,,,,,

,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,, ,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,

30.950"

SUBJECT:

Section

01110807

BP EXPLORATION


Section

:

2705/GEN

Rev.

:

2 (1/94)

Page

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9 of 10


Lynx H.D. 3 off Safety Bolts

7 off M30 Jacking Screws

Jacking Bolts Screwed in Hand Tight 1 2

3

4

5

6

Sequence of Screwing in Jacking Screws for:Make-Up (1-7) & Separation (7-1)

7

Jacking Bolts Screwed Fully in

S.Morrison, Dec. 1993, 01110051

Box/Lockring Lifted Away

BP EXPLORATION


Section

:

2705/GEN

Rev.

:

2 (1/94)

Page

:

10 of 10


NOSE

BODY GROOVE

DETAIL SHOWING FITTED POSITION OF LIP SEAL IN GROOVE

CORRECT FITTING

INCORRECT FITTING 2179/113

BP EXPLORATION


Section

:

2715/GEN

Rev.

:

1 (12/89)

Page

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1 of 11

CONNECTORS: VETCO SR-20

INTRODUCTION The SR-20 is a fast make-up, releasable connector for universal platform conductor applications. The connector makes up with an interference fit, which results in the high radial preload necessary for driving and long operational life. The SR-20 connector does not require rotation or pressure injection to make-up. The unique two-start threads on the pin and box can be made up with either a clamp tool supplied by Vetco Gray, or if the string is bottom supported with a single dry blow from a pile hammer. The connector can be released by rotation and pressure injection.

2.

SR-20 CONNECTOR DESIGN FEATURES -

3.

Strength comparable to X52 pipe. Fast make-up without the use of rotation. Releasable/reusable. Fully radially preloaded connection. Bi-directional torque application. Metal to metal sealing. High stab angles. No premature connector engagement. External drive/load shoulder. Installation and handling tools. Alternative make-up methods. Simple, reusable alignment key.

STANDARD SPECIFICATION - 30" SR-20 CONNECTOR Nominal OD (in)

Wall Thickness (in)

Connector Part No.

Connector OD (in)

Connector ID (in)

Length Made Up (in)

30

1.00

83540-2 835540-1

30

27

16.313

Connector Weight (lbs)

Tensile Capacity (kips)

Bending Capacity (kip-ft)

Internal Pressure (psi)

575

4,000

2,560

2,000

Make-Up Models There are three possible methods to make up the SR-20 connector: a) b) c)

Standard: clamp tool. Torque. Pile hammer.

Standard Method Utilising the specially designed clamp tool installed around the connector, a force of 200 tons is applied to snap the box and pin together from an initial stand-off of approximately 5/8" to full make-up.

BP EXPLORATION


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2 of 11


Torque In special situations where the use of the clamp tool is not possible, the SR-20 connector can be made up by the injection of hydraulic oil, applied torque of 15-20,000 ft/lb and 1 turn. The alignment key is installed after make-up, and the retainer and key tack welded together. Hammer A single blow from a hammer of 12,000 ft/lb impact load also makes up the SR-20. The conductor drive string must be bottom supported to prevent rotary table damage. Breakout The SR-20 connector can be broken out by application of 20,000 ft/lb left hand torque while simultaneously injecting hydraulic oil at 1500 psi into the box. The alignment keys are released by prying out the retainer. The connector and alignment key are re-usable. 4.

30" SR-220 CLAMP TOOL The clamping tool is a standard piece of equipment designed for operation with 30" - 27" diameter SR20 connectors. The tool is adapted for use with sizes smaller than 30" by fitting insert sections to the jaws. The clamping assembly is attached to an I beam with an adjustable counter-balance weight to maintain the tool in the horizontal plane when suspended. The clamping assembly consists of two horizontal rings split in three places with hinges at two points and a locking handle device at the opening section of the tool. These two horizontal rings are attached by means of 8 hydraulic cylinders which impart the axial force required to drive the jaw sets axially towards each other and hence snap the connector together. An elevation adjustment cylinder is provided attached to the tool lift eye and enables the tool to be quickly wrapped around the stabbed connection and actuated. This tool requires lifting by tugger lines or a centrally placed lift eye and is no different in this respect to other clamp tools in the market place. The tool is controlled from the local panel mounted in the middle of the I beam. This panel provides local pressure readout and control of tool functions. System hydraulic pressure is supplied to the tool from an air operated hydraulic power unit.

5.

SR-20 HANDLING/CIRCULATING TOOL The handling/circulating tool has been designed to ease the handling and running of SR-20 conductor joints. The design is based on the field-proven marine riser handling tools. The tool has a large "O" ring seal to allow for circulating pressures of up to 500 psi if required. The tool is stabbed over the connector body and a split lockring is latched into the clamp groove on the connector OD by torquing 8 set screws on the tool. A window is provided in the tool body through which the lockring ends can be viewed to verify correct make-up of tool to joint. A drill stem sub is incorporated with a standard 4 1/2" IF box connection up to allow use of drillpipe elevators for lifting and running. Bull plugs are also provided to allow for release of air or fill up when running conductor.

BP EXPLORATION


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:

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3 of 11


The tool is rated for 150 tons of lifting load in combination with 500 psi of circulating pressure. All tools are proof-load tested prior to supply and relevant certification is obtained from Lloyd's Register of Shipping. 6.

SR-20 PIN DRIVE CHASER The chaser joint has been designed for use when the SR-20 connector is either being driven or utilised in a drill/drive operation. The joint consists of a main body incorporating a blank SR-20 box profile that swallows the pin and enables driving loads to pass from the hammer to the conductor string. A pup joint is welded to the top of the main body to take the hammer blows. A short pup with a lower swaged section is welded onto the bottom of the main sub assembly to give good centralisation and aid stabbing of the chaser into the joint prior to driving.

7.

ROUTINE OPERATION A.

Pre-Operational Checks Connectors 1.

Remove thread protectors. Thoroughly clean both pin and box.

2.

Inspect the threads and metal shoulder surfaces. Install "O" rings in the grooves provided in both the pin and the box.

Clamp Tool 3.

Inspect the clamp tool for any damage, particularly hydraulic hoses and fittings.

4.

Attach lift cylinder and hoses to tool. Connect power supply hoses to tool. Connect rig air to power supply. Check reservoir level.

5.

The hanger cylinder and pull-back winch should be checked, the hanger cylinder should be cycled to the full stroke and the pull-back winch function tested.

B. Running Procedures General Notes Recommended Lubricant - Jet Lube AP-5. Apply a thin coating of grease to the thread areas, seal areas, and drive shoulders of both the pin and the box. The entire surface should be lightly coated. CAUTION: Do not use thread dope or lubricants which contain metal or metallic compounds. Do not use any locking compounds. These materials will not allow the connector to make up fully, and can prevent the connection from releasing. 7.1

Clamp Tool Make-Up 1.

Stab the box over the pin with the slot in the box oriented with the alignment key on the pin.

2.

Open both lower and upper clamps and swing segments open. Push tool across connector, aligning the upper clamp lip of the rear segment with the box clamp groove.

BP EXPLORATION


7.2

Section

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4 of 11


3.

Open relief valve to extend clamp tool cylinders. If necessary, open needle valve to adjust lower clamp lip to fit into clamp groove. Close valve.

4.

Swing left-hand segments closed, followed by the right-hand segments. Secure with upper and lower latch handles.

5.

Verify system pressure is available at power supply.

6.

QUICKLY open the ball valve on the tool panel to actuate clamp tool.

7.

Close the ball valve. Operate the extend valve to extend lower clamp for making the next connection.

8.

Ensure that the connector is properly made up. There should be no gap at the shoulder. The box and pin should be flush within 0.025" (0.06 cm).

Hammer Make-Up 1.

Install plug in the pressure port.

2.

Stab the box over the pin with the box slot oriented with the pin key. Verify the gap between the box and pin shoulder does not vary more than 1/8" (0.32 cm) total around the circumference. CAUTION: This must be a dry starting blow. Do not allow the hammer to run until the connection has been inspected for complete make-up.

7.3

3.

Lift and drop the pile hammer piston. Verify the connector is properly made up. There should be no gap at the shoulder, and the box and pin should be flush within 0.025" (0.06 cm).

4.

Install plug in the pressure port.

Threaded Make-Up 1.

Remove the alignment key from the pin.

2.

Stab the box over the pin with the slots aligned to within ± 1" (2.54 cm).

3.

Screw the box onto the pin clockwise no more than 3/4 turn. At this point, the torque will increase measurably.

4.

Connect a pressure hose to the port in the box.

5.

Maintain a torque of between 10,000 to 15,000 lb-ft (13 558 to 20 337 N.m) and slowly increase the injected pressure. This will allow the connector to rotate until the key slots are aligned. Do not allow pressure to exceed 1,500 psi (10 342 kPa).

6.

Verify the connector is properly made up. There should be no gap at the shoulder, and the box and pin should be flush within 0.25" (0.05 cm).

7.

Disconnect pressure hose and install pressure port plug.

8.

The alignment key is not required, but if it is desired, it may be installed and secured by welding the key to the retainer.

Before moving onto the next connection, install the connector protection system (procedure to be advised).

BP EXPLORATION


7.5

Section

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Breakout 1.

Remove the alignment key by prying out the retainer and sliding the key downward and out.

2.

Remove pressure plug and install pressure hose.

3.

Apply 10,000 to 15,000 lb-ft (13 560 to 20 340 N.m) torque to the connection. Then apply 1,500 psi (10 342 kPa) to the hose, closing the valve after the connector has begun to turn.

4.

Supporting joint weight on the hook, apply torque to unscrew the connector about one complete turn.

Alignment Key Replacement

Note: This procedure may only be used to install a key on an unconnected pin. Previously used keys and retainers may be re-used by first removing the broken portions of the spring pins with a suitable drift.

7.6

8.

9.

1.

Install a new spring pin in the retainer. Press or hammer the pin until it is flush with the far side.

2.

Place the retainer inside the slot in the pin with the notches facing the body of the pin. Install the alignment key in the slot until the top of the spring pin begins to enter the hole in the bottom of the key (see Figure E).

3.

Using a small hammer, tap the alignment key downward as far as it will go, taking care not to damage the threads on the connector.

Troubleshooting Problem:

Excessive pressure is injected into the annulus during breakout. Connector separates on one side and "O" ring extrudes through the gap.

Solution:

To complete breakout, it will be necessary to reshoulder the connector where it has separated. This may be done with either the clamp tool or the hammer. If neither is available, a tugger line can be attached to the conductor to pull on the assembly and snap the connector together fully.

RECOMMENDED SPARES "O" Rings

-

four extra per string.

Lockring Key, Retainer and Spring

-

two extra per 8 joints.

Injection Port Plug

-

two extra per string.

DISASSEMBLY/ASSEMBLY AND TEST PROCEDURE None required.

SUBJECT:

ID

Made-Up Length

Tensile Kips

Compr. Bending Kips Kips ft

Int. Press. psi

Tensile Kips

Bending Kips ft

Int. Press. psi

1440

2420

X56 PIPE 26" x 0.625"

26.25"

23.25"

16.37"

3063

4248

1746

2000

2790 X52 PIPE

26" x 1"

26.25"

23.25"

16.37"

3063

4248

1746

2000

4048

2049

3500

27" x 1.25"

27.53"

24.50"

17.37"

3700

4800

2200

2000

5258

2697

4213

30" x 1"

30"

27"

17.37"

4000

5000

2560

2000

4738

2770

3120

32" x 1"

32.53"

29.50"

17.37"

4000

5425

2800

2000

5064

3173

2500

960

3650

BP EXPLORATION

OD

DRILLING MANUAL

Nom. Size x Wall


SR-20 RANGE CONNECTOR PROPERTIES

X65 PIPE

2715/GEN

2470

:

3660

Section

1000

1 (12/89)

2500

:

2500

Rev.

13"

6 of 11

18.75"

:

21.75"

Page

20" x 0.625"

BP EXPLORATION


Section

:

2715/GEN

Rev.

:

1 (12/89)

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SR-20 SEALS

'O'-RING SEALS

METAL TO METAL SEAL AREAS

2179/110

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30" O.D. x 1" WALL SR-20 CONNECTOR ASSEMBLY

Ø30.03 Ø20.00

SHOWN 90° OUT OF PHASE

11.00 16.37 13.34

Ø27.00

2179 / 89

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CONNECTORS: VETCO SR-20 FIGURE 1

LAYOUT, SR-20 CLAMP TOOL, MKII

ELEVATION CYLINDER PULL-BACK WINCH

PROTECTIVE COVER

ACTUATOR SUPPORT

CA SP EP

EC AM

TE

CT

CONTROL PANEL

UPPER CLAMP ASSEMBLY LATCH

LOWER CLAMP ASSEMBLY HYDRAULIC CYLINDER 4" STROKE x 1 3/4" DIA x 8" STROKE

LEGEND EP

ELEVATION CYLINDER PRESSURE

EC

ELEVATION CYLINDER

CA

CLAMP POSITION ADJUSTMENT

SP

SYSTEM PRESSURE

TE

TOOL EXTENDER

CT

CLAMP TOOL ACTUATOR

AM

ACTUATOR MANIFOLD MOTOR

2179 / 88

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BULL PLUG (SHOWN OUT OF PHASE)

SEAL ASSEMBLY

DEPRESSOR SCREW

LOCK BLOCK

LOCK RING

4 - 1 /2" IF PIN CONNECTION

2179/87

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LAYOUT, DRIVE CHASER SR-20 27"

2179/86

BP EXPLORATION


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CONNECTORS: VETCO ALT SERIES

INTRODUCTION The ALT-2 connector is a Squnch Joint which is a threadless automatic lock/mechanically releasing connector which requires no rotation for make-up. It is designed to save expensive rig time with its extremely fast make-up characteristics. Squnch joints are well suited for connecting large diameter conductor casing joints. They are also often used to connect the last joint of casing to the wellhead housing extension. These weight set connectors ensure that the casing joints are run efficiently and safely, in spite of extreme casing weight and vessel movement.

2.

DESIGN CHARACTERISTICS The 30" x 1" ALT-2 Squnch Joint was designed with the following features, listed below. • • • • • • • • • •

3.

High strength. Easy stabbing. Easy mechanical release. High pressure seal. Driveability. Reusability. Weldable materials. Self-centring locking ring. Wide landing shoulders. Tolerance to contamination.

TECHNICAL TOOL DESCRIPTION Vetco Squnch Joint Connectors are automatic lock, mechanical release connectors. They are pressure tight joints that do not require rotation to make them up. Their most common use is for quick connection of large diameter conductor and casing in offshore drilling operations. There are three main types of Squnch Joint connectors. Type ST-2 Squnch Joint is designed to be run into pre-drilled holes. This joint can be used in conductor strings that require moderate hammer driving. Type ALT-2 Squnch Joint is designed for medium to severe driving conditions. It is a joint that when properly maintained can be used on a continued well-to-well program and can be driven to refusal without damage. Type ATD Squnch Joint is designed for conductor casings that are run into pre-drilled holes, and can be used in light to medium driving conditions, but not on a continued well-to-well program. The recovered joints should be replaced and used in the conductor driven below mudline after use on three or four wells.

4.

SPECIFICATIONS Metric equivalents used in Vetco procedures are expressed in SI units as illustrated below:

Quantity

English Unit

SI Units

SI Symbol

Multiplier

Pressure Weight Torque

PSI Pounds Pounds-Foot

Kilopascals Decanewtons Newton Metres

kPa daN N.m

6.895 0.445 1.356

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:

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Refer to drawing for dimensions. Mechanical and pressure ratings on last page.

5.

ROUTINE OPERATION

5.1

Pre-Operational Checks 1.

Section

Thoroughly clean the pin and box. Examine the "O" rings and lockrings and replace any that are damaged. Ensure that the lockring is free to move in the lockring groove. If some joints will be recovered for re-use, run a tap into each releasing bolt hole and blow out any debris with rig air. Then liberally grease the threads in each releasing bolt hole. IMPORTANT: Lubricants containing metallic particles such as drillpipe thread dope must not be used on these connectors.

5.2

2.

Lightly grease the Squnch Joint pin profiles.

3.

If the Squnch Joint pin is equipped with an alignment lug, ensure that the lug is not damaged or loose.

Running Procedure General Notes Vetco recommends that Squnch Joints are run box down. This method provides optimum resistance to damage when handling. Some Squnch Joints are not equipped with alignment lugs. To assist with releasing these connectors, locate the lockring gap and place a paint mark on the outside opposite the gap. To make up these connectors, simply position the box over the pin and slack off. If conductor or casing joints fitted with Squnch Joint connectors will be recovered and re-used, make certain the plastic plugs supplied with each box connector are fitted in the releasing screw holes after checking lockring make-up, just before running. 1.

With the first joint of conductor or casing landed at the rotary table and the next joint suspended from the blocks, check the lockring groove in the box member to assure it is free of debris, that may have lodged there while picking up the joint. Align gap in the lockring with alignment lug on Squnch Joint pin. This will provide a reference point for the lockring gap location and will assist in separating connectors.

2.

Rotate the suspended joint until the alignment slot of the box connector lines up with the alignment lug on the pin connector. Lower the joint until the lug enters the slot then slack off quickly to make up the connection.

3.

Verify that the lockring is fully engaged in the lockring groove on the box member. This can be visually checked through the releasing screw holes on the box member, or by inserting a depth gauge into the releasing screw holes. A short piece of welding rod correctly marked can be used as a depth gauge.

4.

Type ATD Squnch Joints have windows in the box member and use a lock block to expand the lockring, securing the pin and box together. Insert the lock block in the window with the ends of the lock block under the ends of the lockring. Drawing 75022 illustrates this procedure. Hit the square end of the lock block with a hammer, and drive it into the lockring groove. In the fully locked position, the lock block does not extend beyond the outside surface of the box connector.

IMPORTANT: Type ATD Squnch Joints must not be run without the lock blocks in place.

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Post-Operational Maintenance Maintenance will be necessary when Squnch Joints are recovered, normally after driving operations.

6.

1.

Wash the pin and box with fresh water. Examine the "O" rings and lockrings, and replace any that are damaged. Ensure that the lockring is free to move in the lockring groove of the pin.

2.

Clean the lockring groove on the box connector, and check that the lower edge retains a square profile. This is particularly important where the Squnch Joint has been exposed to severe driving conditions.

3.

Apply a corrosion inhibitor to pin and box connector surfaces. Install protectors and place in storage on racks.

RECOMMENDED SPARES Refer to Spare Parts Kit or Suggested Spares List.

7.

DISASSEMBLY/ASSEMBLY AND TEST PROCEDURE

7.1

Disassembly

Note: It is good practice to first make up the releasing screws opposite the gap in the lockring, and then make up the other releasing screws from this point around to the gap. On connectors without alignment lugs, the gap in the lockring can usually be located by referencing the paint mark applied at make-up or by poking a piece of welding rod into the releasing holes on the box. To Separate Connectors

7.2

1.

The lockring can be depressed by screwing 1/2"-13NC thread bolts in the tapped holes provided. The bolts must be long enough to depress the lockring before the bolt threads bottom on the connector. Run each bolt in until tight, then back off 1/2 turn. Pick up on the Squnch Joint box to disconnect the joint.

2.

On type ATD Squnch Joints, remove the lock block by running a 5/8"-11NC x 3 1/2" long bolt into the threaded hole in the centre of the lock block. Make up the bolt until the lock block is jacked out of the lockring groove.

Assembly None required.

7.3

Test Procedure Some Squnch Joint boxes are equipped with a test port, and have "O" ring seals above and below that port. After make-up, maximum test pressure of 500 psi (3 447 kPa) may be applied to the test port. At the completion of the pressure test, remove the pressure fitting and re-install the small pipe plug.

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VETCO ALT SERIES AND SQUNCH JOINT CONNECTORS NOMINAL MECHANICAL PROPERTIES

Size

Type

MSP (1)

Tensile

Bending

30"

ST-2

1,500 PSI 10 343 kPa

2,130,000 lbs 947 075 daN

1,900,000 lb-ft 2 576 000 N.m

30"

ATD

1,500 PSI 10 343 kPa

2,320,000 lbs 1 032 000 daN

1,756,000 lb-ft 2 372 650 N.m

30"

ALT-2

2,500 PSI 17 237 kPa

5,720,000 lbs 2 545 000 daN

4,000,000 lb-ft 5 423 000 N.m

20"

ST

1,500 PSI 10 343 kPa

1,000,000 lbs 445 000 daN

400,000 lb-ft 542 320 N.m

20"

ATD

3,000 PSI 20 685 kPa

1,500,000 lbs 667 500 daN

600,000 lb-ft 813 480 N.m

20"

ALT-2

4,000 PSI 27 580 kPa

2,430,000 lbs 1 081 000 daN

1,120,000 lb-ft 1 518 000 N.m

NOTE:

(1) MSP - Maximum Service Pressure.

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ALT-2 CONNECTOR 30" x 1" WALL

2179 / 85

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ASSEMBLY CONNECTORS BOX 30" TYPE ADT 2"

2179 / 84

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ASSEMBLY CONNECTOR BOX 30" TYPE ADT 2"

2179 /83

BP EXPLORATION


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CONNECTORS: VETCO RL4S

DESCRIPTION Connector features a four start thread which provides for full make-up with between one-quarter and one-half turn of the suspended joint. A stabbing indicator and two positive full make-up indicators are provided. Once the joint is fully made up and both indicators checked, an anti-rotation device is activated.

2.

TOOLS REQUIRED Rig tongs or power tong. Hilti gun and cartridges for shearing anti-rotation tab.

3.

PREPARATION OF CONNECTORS

3.1

Remove protectors, clean both pin and box thoroughly, inspect threads for damage.

3.2

Monitor installation of O-ring in box connection.

3.3

Lubricate both pin and box with gear oil, heavy oil or a light molybdenum based grease. When using grease, Jet-lube AP-5 is recommended. DO NOT USE THREAD DOPE OR LUBRICANTS CONTAINING METAL OR METALLIC COMPOUNDS. These compounds may prevent the threaded connector from making up fully and can prevent the connection from sealing.

4.

RUNNING PROCEDURE To ensure correct make-up of the connection, alignment marks are painted on both the pin and box members. Stabbing and Torquing of Connection

4.1

Pick up joint and suspend above box connection in rotary table.

4.2

Align the stab-in arrowhead on the pin with the stab-in zone on the box. Figure 1.

4.3

Slack off ALL the weight of the joint hanging in the elevators. The stand-off between the top of the box and the indicator shoulder of the pin should be approximately 1/4”.

4.4

Torque up the joint. The joint should rotate 135 degrees. Torque will be low until the last few degrees of rotation, when it will increase rapidly. At full make-up position the stab indicator on the pin will align with the make-up indicator zone on the box. Figure 2. (Refer to tables for maximum and minimum torque values.)

4.5

As a final check on correct make-up the indicator shoulder on the pin should be exactly flush with the top shoulder on the box. Figure 3. THE FLUSH ALIGNMENT OF THE INDICATOR SHOULDER IS THE PRIMARY INDICATION OF PROPER MAKE-UP AND SHOULD BE CHECKED AT 4 PLACES, 90 DEGREES APART, PRIOR TO PICKING UP WITH THE BLOCKS AND REMOVAL OF SLIPS.

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Failure of Pin Arrow to Align with Box Make-Up Zone If the joint has been fully torqued up but the alignment marks fail to meet or the indicator shoulder is not flush - breakout the connection. To break out the connection, apply left hand torque with the tongs. 1/4 to 1/2 turn is enough to disengage the thread. Inspect both pin and box connections for debris or damage. If no obvious fault is found, stab the pin as above and torque up the connection. If the connections again fail to make up correctly, lay out the suspect joint. 5.

ACTIVATION OF ANTI-ROTATION DEVICE Install Hilti gun with shearing hammer fully fitted into groove in box. Fire gun; metal tab will be forced into the groove in the pin. To break out connection, if required, prise out the locking tab until clear of the slot in the pin. RL4S Connector - Make-Up Torque

RL-4S

Make-Up Torque (ft-lbs) Min. Max.

16”

18,000

25,000

18 5/8”

18,000

25,000

20”

22,000

25,000

24”

24,000

28,000

26”

26,000

30,000

22,000

25,000

RL-4C 20”

Notes: 1. Breakout torques are within 10 percent of make-up torques. This can vary in driving applications where breakout torques could be significantly higher. 2. Anti-rotation device provides approximately 400 ft.lbs/in of connector diameter torque resistance per tab.

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STAB INDICATOR ARROW PIN

PIN

STAB ZONE

BOX

MAKE-UP INDICATOR ZONE

FIGURE 1 STABBED POSITION

BOX

FIGURE 2 MADE-UP POSITION

INDICATOR SHOULDER FULLY MADE UP

PIN

BOX

FIGURE 3 2233/5

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BP STANDARD CASING DATA

1.

Dimensional and strength data for the standard casing used in BP operations is given in Tables 1 to 4.

2.

NEW VAM threads are compatible with the previous VAM, VAM ATAC, VAM AG and VAM AF connections. The following chart instructs which torque is applicable when previous products and NEW VAM are assembled together in the same string, on pipe or accessory connections. BOX

NEW VAM NEW VAM M.S. (1)

VAM VAM ATAC

VAM AG VAM AF

NEW VAM S.C. VAM S.C. (2)

NEW VAM NEW VAM M.S. (1)

NEW VAM torque

NEW VAM torque

NEW VAM minimum torque ± 10%

NEW VAM torque

VAM VAM ATAC

NEW VAM torque

NEW VAM torque


NEW VAM torque

VAM AG VAM AF

NEW VAM torque

NEW VAM torque


NEW VAM torque

NEW VAM S.C. VAM S.C. (2)

NEW VAM torque

NEW VAM torque


NEW VAM torque

PIN

(1) M.S. = Matched Strength.

(2) S.C. = Special Clearance.

Note: a) The VAM ACE thread is not compatible with any existing VAM product. b) VAM ACE and NEW VAM can be easily recognised in the field as each connection is low-stress die stamped around the middle of the coupling.

18 5/8

18 5/8

18 5/8

18 5/8

Grade

X52

X52

X52

X52

K55

X56

X56

X56

K55

X56

X56

X56

X56

X56

X56

X56

Weight (lbs/ft)

310

457

310

310

94

94

94

94

133

133

133

133

87.5

87.5

Body ID (inches)

28

27

28

28

19.122

19.122

19.122

19.122

18.728

18.728

18.728

18.728 17.756 17.756

17.375 17.375

Drift ID (inches)

28

27

26.5

28

18.936

18.00

18.00

18.63

18.542

18.00

18.00

18.563

17.75

17.58

17.375

Wall Thickness (inches)

1.0

1.5

1.0

1.0

0.438

0.438

0.438

0.438

0.625

0.625

0.625

0.625

0.435

0.438

0.625

Tensile Yield (Kip)

4738

6985

4738

4738

1479

1480

1480

1850

2123

2090

2090

1800

1240

1350

1750

Burst Pressure (psi)

3120

4680

3120

3120

2110

2210

2210

2210

3060

3150

3150

3150

2290

2290

3290

Collapse Pressure (psi)

1630

3910

1630

1630

520

520

520

596

1500

1450

1450

1652

630

630

1710

Capacity (bbl/m)

2.4988

2.3248

2.4988

2.4988

1.165

1.165

1.165

1.165

1.118

1.118

1.118

1.118

1.005

1.005

1.005

Metal Displacement (bbl/m)

0.3697

0.5434

0.3697

0.3697

0.111

0.111

0.111

0.111

0.159

0.159

0.159

0.159

0.104

0.104

0.104

Hunting Hunting Hunting Lynx SA Lynx HD Merlin

Vetco SR20

BTC

Vetco LS-2

GEM

RL 4S

BTC

Vetco LS-2

GEM

RL 4S

Vetco LS

RL 4S

Vetco LS

21.0

21.5

21.0

21.5

21.0

21.5

21.0

21.5

20.125

20.38

20.125

18.0

18.0

18.63

18.542

18.0

18.0

18.63

17.75

17.58

17.375

1890

1480

1800

2123

2430

2090

1800

1240

1350

1750

14,000

20,000

18,000

14,000

20,000

18,000 13,000

13,000

24,000

25,000

25,000 23,000

23,000

Coupling Type Coupling OD (inches)

33.5

34.1

30

30

Coupling ID (inches)

28.6

27.0

26.5

27.0

Coupling Tensile Yield (Kip)

3200

6970

3500

4000

Minimum Make-Up Torque (ft/lbs)

N/A

N/A

N/A

N/A

Optimum Make-Up Torque (ft/lbs)

N/A

N/A

N/A

N/A

Maximum Make-Up Torque (ft/lbs)

N/A

N/A

N/A

N/A

Remarks

1479

*

* 24,000

* Base Triangle

25,000

25,000 * Base Triangle

TABLE 1 - BP STANDARD CASING DATA

0.625

RL 4S

2800/GEN

20

:

20

Section

20

BP EXPLORATION

20

0 (9/90)

20

:

20

Rev.

20

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20

:

30

Page

30

DRILLING MANUAL

30


30

SUBJECT:

Casing OD (inches)

13 3/8

13 3/8

13 3/8

13 3/8

9 5/8

9 5/8

9 5/8

9 5/8

9 5/8

9 5/8

9 5/8

K55

X56

K55

N80

N80

HC95

P110

N80

L80

HC95

P110

L80

SR95

HC95

75

133/72

68

68

72

72

72

47

47

47

47

53.5

53.5

53.5

Body ID (inches)

15.122

12.346

12.413

12.413

12.346

12.346

12.346

8.681

8.681

8.681

8.681

8.535

8.535

8.535

Drift ID (inches)

14.937

12.26

12.26

12.26

12.25

12.25

12.25

8.525

8.525

8.525

8.525

8.5

8.379

8.5


0.438

0.48

0.48

0.514

0.514

0.514

0.472

0.472

0.472

0.472

0.545

0.545

0.545

Tensile Yield (Kip)

1178

1069

1556

1661

2168

2285

1086

1086

1606

1493

1244

1477

1781


2630

3450

5020

5380

6990

7400

6870

6870

10120

9440

7930

9410

10730


1020

1950

2260

2670

3690

2880

4750

4750

7060

5310

6620

7330

8920

Capacity (bbl/m)

0.729

0.491

0.491

0.486

0.486

0.486

0.2402

0.2402

0.2402

0.2402

0.2322

0.2322

0.2322


0.088

0.08

0.08

0.086

0.086

0.086

0.056

0.056

0.056

0.056

0.064

0.064

0.064

Coupling Type

BTC

RL 4S/BTC

BTC

BTC

BTC

VAM

New VAM

New VAM

New VAM

New VAM

New VAM

New VAM

New VAM

New VAM

17.000

21.50

14.37

14.37

14.37

14.39

10.65

10.65

10.65

10.65

10.65

10.65

10.65

1300

1300

1691

1086

1086

1497

1493

1243

1458

1637

Grade Weight (lbs/ft)

Coupling OD (inches) Coupling ID (inches) Coupling Tensile Yield (Kip)

18.75 1329

1800/

Replaces K55

Special Drift * Base Triangle

14400

14400

15900

15900

14050

14450

15900

15900

15900

15900

15900

17400

17400

15850

15850

17400

17400

17400

17400

17400

Special Drift

Special Drift

2800/GEN

* Base Triangle

14400

:

Contingency

14400

Section

Remarks

*

14400

0 (9/90)

25,000/

7180

13050

:


*

13050

Rev.

/7180

14400

3 of 5


14400

:

18,000/

Page


1975

BP EXPLORATION

13 3/8

DRILLING MANUAL

20 x 13 3/8 Swage


16

SUBJECT:

Casing OD (inches)


Special Drift

Special Drift Clyde only

7

7

7

7

7

7

7

7

7

7

7

7

Grade

P110

XT-155

N80

XT-140 22%CR

N80

L80

P110

XT-155

XT-140 22% CR

HC95

P110

SM110TT

L80

SR95

P110

Weight (lbs/ft)

53.5

53.5

39

26

29

29

29

29

29

32

32

32

35

35

35

Body ID (inches)

8.535

8.535

6.626

6.276

6.185

6.185

6.185

6.185

6.185

6.094

6.094

6.094

6.004

6.004

6.004

Drift ID (inches)

8.5

8.5

6.5

6.151

6.059

6.059

6.059

6.059

6.059

5.969

5.969

5.969

5.879

5.879

5.879


0.545

0.545

0.500

0.362

0.408

0.408

0.408

0.408

0.408

0.453

0.453

0.453

0.498

0.498

0.498

Tensile Yield (Kip)

1710

2410

893

1057

676

676

929

1310

1183

1035

1017

1053

814

966

1017


10900

15360

9181

12670

8160

8160

11220

15810

14280

12520

12460

12460

8460

11830

13700


7930

9020

8818

6690

7020

7020

7820

9890

9560

11300

10760

13850

10180

11640

13010

Capacity (bbl/m)

0.2322

0.2322

0.140

0.1255

0.1219

0.1219

0.1219

0.1219

0.1219

0.1184

0.1184

0.1184

0.1149

0.1149

0.1149


0.064

0.064

0.046

0.031

0.035

0.035

0.035

0.035

0.035

0.038

0.038

0.038

0.042

0.042

0.042

Coupling Type

New VAM

New VAM

AB FL-4S

New VAM

New VAM

New VAM

New VAM

VAM ACE

VAM ACE

New VAM

New VAM

New VAM

New VAM

New VAM

New VAM

Coupling OD (inches)

10.65

10.65

7.625

7.681

7.681

7.681

7.681

7.657

7.657

7.681

7.681

7.681

7.681

7.681

7.681


6.55

7.39

BP EXPLORATION

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DRILLING MANUAL

9 5/8


9 5/8

SUBJECT:

Casing OD (inches)


1710

2323

728

1040

676

676

929

1282

1164

920

997

997

725

923

997


14400

14400

7500

9850

8460

8460

9850

11450

11450

9850

10450

10450

9500

10100

10850


15900

15900

10850

9400

9400

10850

12650

12650

10850

11550

11550

10500

11200

11950

Page

Rev.

Section


17400

17400

11850

10340

10340

11850

13850

13850

11850

12650

12650

11500

12300

13050

:

:

:

Remarks

Special Drift

Special Drift

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0 (9/90)

2800/GEN

Forties Only

Clyde Only

Clyde Only


Special Clearance & Special Drift

4 1/2

4 1/2

4 1/2

XT-155

N80

P110

L80

SM80

22% CR

35

23

18

12.6

12.6

12.6

Body ID (inches)

6.184

4.669

4.276

3.958

3.958

3.958

Drift ID (inches)

5.879

4.545

4.151

3.833

3.833

3.833


0.498

0.415

0.362

0.271

0.271

Tensile Yield (Kip)

1577

531

580

288

288


19300

10573

13938

8430

8430


16570

11168

13445

7504

7504

Capacity (bbl/m)

0.1149

0.0695

0.0582

0.049

0.049


0.042

0.027

0.022

0.014

0.014

Coupling Type

New VAM

AB FL-4S

New VAM

New VAM

New VAM

VAM ACE

Coupling OD (inches)

7.681

5.5

5.587

4.892

4.892

4.961

4.595

5.39

Grade Weight (lbs/ft)


6060

4300

4300


12650

6730

4770

4770


13850

7400

5240

5240

Remarks

Forties/ Magnus Only

Special Clearance & Special Drift

West Sole Only


Clyde Only

2800/GEN

5000

:

11450

Section


0 (9/90)

288

:

288

Rev.

580

5 of 5

431

:

1450

Page


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7

SUBJECT:

Casing OD (inches)

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TUBING PREPARATION AND RUNNING PROCEDURES

1.

GENERAL

1.1

The procedures outlined cover all carbon steel premium tubulars and can also be selectively applied to API tubulars. Premium tubular can be defined as any pipe with a connection incorporating a built-in gas tight metal to metal seal.

1.2

It is recommended that a Tubing Supervisor be used when running VAM tubing 7” or smaller in size. The decision to use a Tubing Supervisor for Hydril connections is optional and, together with the decision to use a Supervisor for VAM tubing above 7”, is at the discretion of the operating group.

1.3

The following procedures are guidelines and should be regarded as a minimum requirement.

2.

RESPONSIBILITIES

2.1

Tubing Inspector/Supervisor (if required) The Tubing Inspector/Supervisor must be fully conversant with the type of premium connection being run. If it is VAM being run he should have attended the “VAM School for Inspectors” and possess a certificate of confirmation. The Tubing Inspector/Supervisor must be able to give a statement about the condition of the connections and decide whether to reject or pass any connection based on field experience and theoretical knowledge. The third party tubular inspection company, employer of the Tubing Inspector/Supervisor, should demonstrate to BP that the above is complied with. The responsibilities of the Tubing Inspector/Supervisor will be as follows:

2.2

1.

To run tubing in accordance with these procedures unless otherwise agreed with BP Drilling. The Supervisor is to be present on the rig floor during running and pulling of the tubulars.

2.

Report to the BP Drilling Supervisor on all aspects of the work.

3.

Supply the correct stabbing guide for the tubing being run.

4.

Liaise with the drill crew, casing crew and BP Drilling Supervisor/Drilling Engineer, ensuring all parties are aware of the procedure to be adopted during preparation and running of tubulars.

5.

Co-ordinate and supervisor running of the job with BP personnel.

Tubular Make-Up Contractor Responsibilities include: 1.

Positioning of tong systems in conjunction with rig crews.

2.

Application of torque to limits set by Tubing Supervisor/BP Supervisor with respect to values, speed, etc.

3.

Provision of a Computer Technician to ensure integrity of electrical installation and verification that all displayed signals, etc., are correct.

4.

Advising Tubing Supervisor/BP Supervisor on the results of graphical analysis and general running performance of tubulars.

5.

Provision of a stabber to stab pipe at all times and support the tubing until shouldering has taken place.

6.

Setting elevator on pipe in conjunction with rig crew.

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BP Supervisor/DE Responsibilities include: 1.

Ensuring that all relevant rigsite personnel involved in running tubulars are aware of their responsibilities.

2.

Ensuring correct use of equipment, procedures, application of technical standards and final acceptance of joints throughout the operation.

3.

To record any deviation in programme, running list, equipment performance, personnel performance and details of minor repairs to connections (making a note of tally numbers).

4.

To ensure safe working practices are adopted.

Note: It is recommended that offshore operational Drilling Engineers and BP Supervisors, who are frequently involved in the running of VAM tubulars, should attend the VAM School. 3.

GENERAL PRINCIPLES The following general principles should be followed:

3.1

3.2

Handling of Tubing a)

Ensure threads are thoroughly clean and free from any dirt or grease, dry and protected (using clean protectors) wherever possible.

b)

Clean threads thoroughly using a steam jet with detergent or solvent. DO NOT use diesel. Ensure that, prior to make-up, connections are fully dry before application of grease/dope.

c)

Protectors must be fitted and fitted correctly when moving pipe. (They should be left on until the last practicable moment.)

d)

Use a storage compound on the threads for extended storage periods (Rust Veto AS, Kendex Orange or Atlas Bradford Premium).

Running In a)

Apply uncontaminated API thread compound to all box threads and seal areas. Apply also to pin seal and bottom half of threads.

Note: Do not apply the thread compound to the box threads when the joint is in the rotary table.

3.3

b)

Stab carefully, using correct stabbing guide.

c)

Make up slowly, particularly the first few threads, and whilst shouldering out.

Pulling Out a)

Break-out slowly and stop rotating immediately the pipe jumps.

b)

Perform regular visual inspection of threads whilst pulling out.

c)

Stagger connection break-outs if multiple runs are required.

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Ensure that the pipe body and tubing threads are adequately cleaned and protected prior to backload.

Note: Only elastomer/composite protectors are to be supplied with premium pipe. 4.

TUBULAR PREPARATION PROCEDURES

4.1

Where sufficient space is available, tubulars should be offloaded into a holding bay so that the boat may be released. Take great care with this operation as damage can be caused by impact and overstacking the tubular bodies.

4.2

Lay down subsequent rows, supporting them with dunnage to prevent bellying. Stack each layer of dunnage vertically above the previous layer. Lay down on each stack three equally spaced dunnage supports as a minimum.

4.3

Proceed to clean, inspect and protect the boxes as follows: a)

b)

Drift •

Prior to drifting, dimensionally check drifts across two diameters at each end (if solid drift used, check also at midpoint). The drift OD must always be sized to plus tolerance. A 42” drift should be used unless the programme (primarily for wirelining requirements) indicates otherwise.

•

The deck crew should remove pin and box protectors (unless open ended) and carefully insert drift from the box-end without contacting thread or seal areas. To prevent drift damage, do not allow drift to “fall out” of the pin-end, but feed it out carefully.

•

Any pipe which fails the drift test should be rejected. It should have a red band painted adjacent to the box end and “NO DRIFT” painted on the body at mid-point. The position where the drift stuck should also be marked on the pipe-body.

•

Having completed drifting, the OD of all drifts should be rechecked. Any drift not within tolerance should be rejected and replaced prior to the next job.

Blow through the pipe with compressed air to ensure that the pipe is internally clean and dry.

Note: It is important that this is done prior to thread cleaning to avoid moving debris from the bore onto the threads or seals. c)

Connection Cleaning i)

Rig with Steam Cleaning and Air Blast Facilities The rig crew should clean the connection threads/seals (both pin and box) and the protectors with a high pressure steam jet, followed by an air blast to dry the item.

ii)

Rig without Steam Cleaning and Air Blast Facilities Clean threads and protectors thoroughly with high pressure water (preferably freshwater). A de-watering solvent, e.g. “Houghtoclean 500”, should then be applied to the threads and seals using a soft clean brush. After cleaning, inspection and reprotection of each row should be carried out with the minimum delay possible.

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Notes •

Diesel or paraffin should not be used for thread cleaning since, if not fully removed, a lack of lubricant adhesion to thread/seal surfaces can result. Also this type of medium does not effectively clean the thread (it has a tendency to smear). It also attracts foreign debris which can be encapsulated in the thread roots, resulting in galling on make-up.

•

Connections must be dried thoroughly to prevent thread and seal corrosion.

•

Cleaning and drying should be of a quality that will allow all features of the connection to be clearly visible - including any counterbore features of the pin/box, and externally approximately one inch onto the pipe body beyond the pin thread.

•

If required, tubular inspection will be carried out on behalf of the Drilling Department by a contracted competent third party Tubing Inspector/Supervisor.

•

The threads and seal area should be inspected for damage or manufacturing flaws. Check for loose couplings. Refurbish damaged threads where possible. If not possible, mark the pipe clearly with red paint and reject it.

•

Mechanical burrs on threads can be cleaned off using a needle file. Some degree of ovality is acceptable in a pipe as the connection will “round out” on make-up (e.g. in VAM only the first 6 7 threads require a full profile). Only very slight surface corrosion on threads/seals, which can be easily removed by brush or emery cloth, can be accepted.

•

If present, the Tubing Inspector should assess the condition of the pipe body (both internal and external) for excess dirt, scale, residual shotblast mediums, laminations, deep pitting or erosion. Whilst he should be capable of independent action, it is essential that he liaises closely with the deck crew and BP Supervisors, especially if significant rejection rates occur.

d)

Measure each joint and paint its number and length near the middle.

e)

After the threads and protectors are completely dry and clean, light gear oil should be applied to the threads, followed by installation of the protectors. Failure to keep connections dry before installing protectors can lead to thread/seal corrosion due to entrapped water being held inside the pipe bore.

Note: If the tubulars are to be left for more than 10 days at the rigsite, a corrosion protective grease should be applied to the connections (DTD recommend Rust Veto AS, Kendex Orange or Atlas Bradford Premium). 4.4

Agree the rig floor layout and running procedures with the casing crew and drill crew.

4.5

Check all the running equipment as follows: a)

Power Tongs Check the condition of the tongs, particularly the tong dies. The load cell may be calibrated by removing it and suspending a known weight from it. Torque is then calibrated by equating with the effective arm length (specific to the tong). The suppliers hold copies of calibration certificates which may be checked. The tong specifically should have torque output tested up to the maximum anticipated for the job, as well as accuracy of hydraulic load cell versus computer torque output. The tong should also incorporate a dump setting valve which automatically cuts make-up when the maximum torque for the connection is reached.

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Elevators and Slips Check that single joint elevators and slips are in good working order. In particular, check the condition of the slip dies. Perform a trial latch of elevators onto casing/tubing before the job commences.

c)

Stabbing Guide Check this key piece of equipment. It should fit snuggly over the box, extending at least to the inside of the shoulder, in order to prevent the pin seal catching on the box whilst stabbing.

5.

TUBULAR RUNNING PROCEDURES

5.1

Running In 1.

Tubulars should be transferred to the catwalk with both closed end protectors securely fitted. Metallic casing hooks (if used) must NOT be allowed to contact the thread or seal areas when transferring pipe on the pipe deck or to the catwalk. Hook-liftable protectors must be used and left in place until the pipe is safely on the catwalk. Before the joint is picked up through the V-door, remove the pin protector and install a klampon protector (recommended type is Klepo). Loosen but do not remove the box protector. If klampon protectors are not available, leave the pin protector on the pipe.

2.

Pick up the joint through the V-door with the single joint elevators (unless the crane is used to transfer the joint directly into the main elevator).

3.

On the rig floor, inspect the threads and refurbish if necessary.

4.

Whether the dope is applied by soft brush or spray application, the following procedure should be adopted: Box - a smooth even film (no base metal to be seen) over shoulder seal and all threaded surfaces. Pin - a smooth even film over shoulder, seal and all surfaces of the bottom half of the threads (threads adjacent to seal). When high shoulders from torque/turn analysis are repeatedly experienced, dope application should be extended to cover all pin threads. API modified thread dope should be used which has a friction factor of 1. The dope should be free from dirt/grit contamination and water and should be mixed thoroughly before application to threads. It is recommended that the dope be in a warm state before applying to the threads. If available, consideration should be given to using an enclosed spray dope applicator system for the box and/or dope agitator system. A 2” paint brush should be used for dope application if a spray dope applicator system is not used.

5.

Engage the power tong and rotate slowly to make up the first few threads (2 - 3 RPM). The pipe should then be made up in high gear (not to exceed 10 RPM) and low gear selected prior to shouldering out of the pipe. Apply the final torque at 1 - 3 RPM. On premium connections a graphical torque/turn analyser (e.g. JAM, Salvo or Data Trek) is recommended for use to confirm correct make-up for all tubing sizes and casing up to and

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including 9 5/8”. Ensure hydraulic dump setting facility on tong is set to maximum rated torque for the connection, to ensure non-overtorquing. A speed control system should also be used (e.g. Weatherford Acu-torq or Salvesen Speedmaster) which controls thread engagement, make-up and final torquing speed. Sustained final torque should be applied for 3 seconds (it is preferable if make-up of connection is continuous and is not stopped to change gear). Sustained torque should be used to ensure final static torque is recorded, not a dynamic torque.

5.2

6.

Care should be taken when setting slips and lowering the elevators to prevent shock loads and impact damage.

7.

Ensure that after filling tubing or casing from the surface the thread dope has not been washed out from the box threads of the previously run connection. If this has occurred, dry the box threads and seal and re-apply dope.

Pulling Out 1.

The joint should not be in tension when backing out as this will cause the joint to spring out resulting in impact damage. The joint will drop slightly when the thread is fully backed out - do not rotate more than 1/4 turn beyond this point as thread galling will most probably occur. The pipe should be backed out slowly. Initial breakout should be at 1 - 2 RPM, followed by a backout speed of less than 10 RPM. The break-out speed should be considerably slowed before the pipe jumps. A crew member should be deployed on the stabbing board to ensure vertical alignment and to reduce pipe lateral movement.

2.

The pin should be guided out of the box by hand and then lifted clear. The connections should be visually inspected to ensure that the break-out procedure is adequate (full inspection is suggested for the first 20 joints and a frequency then chosen according to the results). This is particularly important if the tubulars are to be re-run.

3.

Before laying the joint down, fit clean elastomeric box and pin protectors to the threads of the newly broken out connection.

4.

When multiple runs are required, e.g. due to leakage, the tool joint breaks should be staggered each trip. (Paint a mark on those joints which have not been broken out, i.e. a circle or star on the unbroken couplings should suffice.) The tubing should be stood back on a wooden mat with elastomeric protectors fitted. Restraining the centre of a stand may be necessary to prevent excessive bowing. For the pipe staggering to work effectively, the driller should clearly mark on his tally those joints which have not been broken. It is very important that when pulling the string, any defect that may have been responsible for leakage be clearly marked and documented prior to correction. If the pipe has been RIH/POOH on more than 4 occasions, then the complete string should be laid down and sent ashore for detailed inspection as per Drilling Inspection Procedure No. 3. A new string should be sent out and RIH.

5.

Before backloading, the tubulars should be cleaned (this applies particularly if running a corrosive fluid such as brine) by hosing down with water (preferably fresh water). The threads should be redoped and clean protectors fitted correctly (made up hand-tight and covering all threads).

Note: When oil based mud is used, cleaning is not normally possible due to pollution considerations. The pipe should therefore be externally wiped clean while pulling out of the hole.


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CHROME TUBULAR HANDLING 13%

1.

INTRODUCTION

1.1

Certain reservoir fluids have, or will have, the combination of CO2, H2S, and a high Chloride content; Chrome duplex alloy may be specified for 7” liner exposed to these types of reservoir fluids. The footage of Chrome tubing run per well will be as advised in the drilling programme.

1.2

These procedures are applicable to all Chrome tubulars being run in CO 2 and low H 2 S environments. Chrome tubulars run in an H2S/CO2 environment are very susceptible to corrosion and sulphide stress cracking. Any action during the storage, handling and running of Chrome tubulars which causes the formation of hot spots (localised hardening) or ferrous inclusions can lead to sulphide stress cracking, hydrogen embrittlement and corrosion. It is therefore essential that more care is taken with these tubulars, than is normally adopted for carbon steel tubulars.

1.3

At all times when handling Chrome tubulars, contact with other metallic equipment, (slings, wire brushes, hammers, etc.) which are not made of a like material should be avoided whenever possible.

2.

TRANSPORTATION

2.1

9 5/8" 13 Cr Tubulars 1.

Metallic slings can be utilised for the shipment of all 9 5/8" 13% casing.

2.

Tubular handling should be witnessed by competent personnel.

Note: If any impact damage is experienced or sustained to an extent that it is clearly visible by a large indentation or the casing drift becomes stuck, then the recommendation is to reject the tubular. 2.2

7" 13 Cr Tubulars 1.

All loose chrome tubulars to be separated by non-metallic dividers.

Note: If chrome is received from suppliers either in racks or transportation boxes, then they can be transported in the same as long as they are in compliance with the appropriate safety and lifting standards and requirements for shipment offshore. 2.

Metallic slings can be utilised for the shipment of all loose 13% Cr if required.

3.


Note: If any impact damage is experienced or sustained to an extent that it is clearly visible by a large indentation or the casing drift becomes stuck, then the recommendation is to reject the tubular. 2.3

5 1/2" and 4 1/2" 13 Cr Tubulars 1.

All loose chrome tubulars to be separated by non-metallic dividers.

2.

If chrome is received from suppliers either in racks or transportation boxes, then they can be transported in the same as long as they are in compliance with the appropriate safety and lifting standards and requirements for shipment offshore.


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3.

Non-metallic or nylon sheathed metallic slings should be utilised for the shipment of all loose 13% Cr.

4.


5.

For low volume use ‘Super 13 Cr’, then cargo baskets can be utilised providing the rows are separated by wood and the individual tubulars on each row by non-metallic dividers.

Note: If any impact damage is experienced or sustained to an extent that it is clearly visible by a large indentation or the casing drift becomes stuck, then the recommendation is to reject the tubular. 3.

RIG-SITE PREPARATION AND INSPECTION

3.1

The BP Drilling Supervisor will conduct a pre-job meeting with the rig crew and casing/tubing running crew to ensure that the proper handling and running procedures are fully understood.

3.2

On arrival at the rig site, tubulars should be carefully unloaded onto the pipe-deck. DO NOT DROP THE PIPE.

3.3

The pipe-deck should be lined with wood, or a similar non-metallic material. Care should be taken at all stages to prevent tubulars having any impact with metal objects.

3.4

Lay out one layer of tubulars on the wooden lined pipe deck.

3.5

Remove the thread protectors (use only wooden or plastic mallets).

3.6

Remove transportation protectors (use only wooden or plastic mallets).

3.7

Drift measure and tally each joint (using a non-metallic drift).

Note: There should not be any loose scale if the tubulars are cleaned and coated correctly. 3.8

Thoroughly steam clean or use a solvent specifically formulated for the removal of storage compounds or thread compounds and dry both box and pin ends. Ensure that all storage compound is removed and the threads are as dry as physically possible. Water or storage compound under the thread compound will affect the coefficient of friction during make-up which may result in incorrect make-ups. DO NOT USE DIESEL OR PARAFFIN AS A CLEANING AGENT.

3.9

On no account should the threads be cleaned with a wire brush. Wire brushing may remove or damage the surface coating. Use a non-metallic bristle brush.

3.10

Visually inspect pipe body, thread, thread coating and the seal areas for any sign of corrosion or damage. Minor damage away from the seal area may be repairable by filing. Any joint that fails the inspection should be rejected. The rejected joint should be clearly marked with a red band and the reason for rejection should be painted on the joint. Rejected joints are to have clean protectors reapplied and joints are to be segregated.

3.11

Steam clean transportation protectors and dry and re-apply to tubing.


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Lay out subsequent layers of tubing ensuring wooden supports between each layer and repeat step 3.5 until all joints have been laid out.

Note: Ensure that when racking tubulars (for 7" no more than 5 rows high), comply with API recommendations. 4.

PRE-JOB CHECKS

4.1

A wooden or rubber lining should be installed on the catwalk and the Vee Door. If this is not possible, tubulars will have to be lifted directly into the Vee Door by the crane.

4.2

In order to ensure all handling tools and tong jaw dies conform to the exacting requirements of high chrome tubing, it is recommended that a single source take responsibility to supply the complete package.

4.3

Check all handling and make-up equipment is on site and meets the specifications laid down in Salvesen Tubular Services recommended equipment list. All tong jaws and handling tool dies shall be checked by the Salvesen Service Supervisor to ensure they are the specified type for running high chrome tubulars, i.e:

4.4

All handling tools should be function tested on the tubulars to ensure correct fit and operation.

4.5

Salvesen Service Supervisor should agree with the Company Representative the parameters to be used, i.e. torque figures and make-up speeds.

4.6

All power equipment (power units, power tongs, Salvos) should be rigged up, calibrated to job parameters and function tested.

5.

RUNNING AND MAKE-UP

5.1

Prior to commencing running operations, the BP Drilling Supervisor should hold a meeting with the Well Services Supervisor, drill crew and Salvesen personnel on the rig floor. This should cover the exact handling and make-up procedure to be used, identify hazards and reinforce safety awareness.

Note: a) Care should be taken at all stages to prevent impact of tubulars against any metal objects. b)

Non-metallic polymer slings should be used for lifting all single joints of tubing.

c) d)

All handling tool dies should be kept clean and changed if necessary. Tong dies should be inspected throughout the running to ensure no wear has occurred, or severe marking of the tubulars is identified.

e)

Ensure correct size of tong is used (i.e. 5 1/2" tong for 5 1/2"/4 1/2" tubing) and tong correctly balanced.

f)

A stabber is recommended for all tubulars.

5.2

Transportation or Klepo protectors may be used to protect threads while lifting tubulars to the rig floor.

5.3

Pick up individual joint using polymer or nylon sheathed metallic slings and carefully lay onto the wood lined catwalk.


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The tubular can then be picked up in either of the following ways (dependent upon rig design):a)

Latch single joint elevator (attached to rig floor tugger) onto the joint and transfer along wooden or rubber surfaces of catwalk and Vee Door to rig floor.

b)

Pick up with crane, using two polymer slings, and transfer joint along catwalk and through Vee Door to drill floor. Carefully latch single joint elevator onto the joint and slacken off weight taken by the crane.

c)

Pick up with crane, using two polymer slings and set down joint directly in the Vee Door. Carefully latch single joint elevator onto the joint and slacken off weight taken by the crane.

Note: It is assumed at this point a downhole packer of sub-assembly has been placed in the rotary table ready for the first joint of tubing. The procedure for such sub-assemblies is exactly the same, extreme care shall be exercised. 5.5

With the joint in the Vee Door, remove the box end protector and visually inspect the thread and seals for mechanical damage.

5.6

The single joint elevator, attached to the blocks, should be carefully fitted and the joint slowly raised to the vertical position with the pin end restrained away from the rotary centre line.

5.7

With the tubular suspended in the single joint elevator, ensure pin end is held a safe working distance from the rotary table, remove protector and inspect threads and seals in accordance with manufacturer's instructions on the pin to ensure no damage has occurred prior to make-up.

5.8

With a clean, soft, 2" paintbrush, apply an even coating of mixed and heated thread compound, from the Dopemaster, to the pin and box joint in the table. Ensure dope is applied as recommended by thread manufacturers. The dope should form an even coating with the threadform still clearly visible through the coating.

Note: If insufficient thread compound is applied, high shoulder torque may be recorded or even galling of threads may result. If excessive thread compound is applied, it may and most probably will be extruded into the bore which may cause problems during wirelining. 5.9

A stab-in guide should be fitted to the box end of the joint in the rotary table and the joint of tubing hanging in the single joint elevator shall be carefully moved into position with the pin end held over the stab-in guide.

5.10

This joint shall be slowly lowered until pin threads are seen to contact the box threads.

5.11

A clear signal should be given to the technician on the stabbing board that the pin and box ends have been engaged correctly and to align the joint for efficient make-up.

Note: A polymer strap wrench shall be fitted by a member of the drill crew. With the assistance of the technician on the stabbing board, the joint should be slowly walked in by hand all the way to the handtight position. If correct thread engagement has not been achieved, then pin should be rotated anti-clockwise until pin drops and engages correctly. 5.12

When the connection has reached the hand-tight position, the power tong can be placed on the pipe. Care should be taken to ensure that the tong is positioned on the tubing without any part of the tong or back-up impacting the tubing wall.


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5.13

The back-up shall be activated to grip the tubing, care should be taken to ensure that the back-up jaws are correctly positioned and are gripping the tubing evenly.

5.14

The tong can now be activated to grip the tubing and the make-up can proceed using the Speedmaster control on the tong.

5.15

The Salvo system will monitor the make-up as it takes place, if accepted the single joint elevator and power tong should be removed at this point and operations will continue as of step 5.17.

5.16

If make-up is aborted for any reason, refer to Section 6, Pulling Out.

5.17

After a satisfactory Graph has been recorded and accepted with the tally number logged on the Salvo, slowly lower the main elevator and carefully position it over the tubing string. The elevator can now be latched.

5.18

Raise the string a short distance so as to enable the hand slips to be removed or the spider to be unlatched. (During the running of the initial joints, a safety clamp may be required; if so this should be removed.)

5.19

Slowly lower the string until the box end is in the correct position for the next connection to be made up. Do not set the slips with the string moving.

5.20

Place the hand slips in position or set the spider and slowly lower the string until the slips engage. Until there is sufficient weight on the string (10 - 20 joints) a safety clamp should be used.

5.21

Carefully remove or unlatch the elevator; if a door type elevator is being used, care should be taken to ensure that the elevator does not impact the tubing wall.

5.22

Repeat the above procedure until the final number of joints have been run.

6.

PULLING OUT If the make-up is aborted for any reason or if the connection requires to be broken out and made up a second time, this procedure should be followed.

6.1

Re-fit the single joint elevator.

6.2

Position tong back-up jaws across coupling. Slowly rotate the tong in the break-out direction until the torque has dropped below the reference level.

6.3

Remove power tong then re-fit the polymer strap wrench.

6.4

Slowly walk out the connection with the assistance of the technician on the stabbing board aligning the joint correctly.

6.5

Do not apply any force to pull the pin from the box. Slowly raise the tubing joint only when the threads have fully disengaged.

6.6

Thoroughly clean both the pin and box prior to inspection, ensuring the pin end is held a safe working distance away from the rotary table.

6.7

If no problems are found with either the threads or the seals, continue with the drying, doping and rerunning of the connection as previously described.


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6.8

If the joint has to be laid out, apply storage compound, fit clean transportation protectors and carefully lift back to the Vee Door, then lift or lower to the pipe deck area. The drill crews should clearly identify the rejected joint by marking with red paint "Reject" and indicate thread damage (TD) or seal damage (SD) and place to one side.

7.

POST JOB CHECKS

7.1

At the end of the job, the Salvesen Services Supervisor shall check the number and state of joints left on deck, i.e. good joints or rejects, including pup joints and accessories.

7.2

He shall ensure all left over joints are doped and protected.

7.3

Check all rejects are red banded and marked "Reject" and "Indicate Damage".

7.4

Ensure all pup joints and accessories are doped and protected.

7.5

After the job is finished, the Salvesen Services Supervisor will complete all relevant paperwork and get it signed by the BP Drilling Supervisor or Well Services Supervisor. The Salvesen Services Supervisor should ensure that all equipment is rigged down and boxed and liaise with the BP Drilling Supervisor or Well Services Supervisor to see if it is being back-loaded.

7.6

If the crew and equipment are staying at the wellsite, then the equipment should be serviced and any extra equipment or spares ordered prior to the next job.

7.7

The tubulars should be back-loaded as soon as possible after completion of the job to minimise exposure to the environment. Use tubular rack or boxes as for transportation to the rig.

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DUPLEX 25% CHROME TUBULAR HANDLING/RUNNING PROCEDURE

1.

INTRODUCTION

1.1

Certain reservoir fluids have, or will have, the combination of CO2, H2S, and a high Chloride content; Chrome duplex alloy may be specified for tubing exposed to these types of reservoir fluids. The footage of Chrome tubing run per well will be as advised in the completion programme.

1.2

These procedures are applicable to all Chrome tubulars being run in CO2 and moderate H2S environments. Chrome tubulars run in an H2S/CO2 environment are very susceptible to corrosion and sulphide stress cracking. Any action during the storage, handling and running of Chrome tubulars which causes the formation of hot spots (localised hardening) or mild steel inclusions can lead to sulphide stress cracking, hydrogen embrittlement and corrosion. It is therefore essential that more care is taken with these tubulars, than is normally adopted for carbon steel tubulars.

1.3

At all times when handling Chrome tubulars, contact with other metallic equipment, (slings, wire brushes, hammers, etc.) which are not made of a like material should be avoided whenever possible.

1.4

These procedures relate to the current Casing Running Contractor for 1992/1993 and have been produced with their involvement which reflects proprietary casing running equipment.

2.

TRANSPORTATION

2.1

Chrome tubulars should preferably be transported on custom built racks to minimise movement and impact during transportation. Packing boxes can be used providing the packaging can be handled offshore.

2.2

All tubular joints should be separated by non-metallic dividers.

2.3

Non-metallic or nylon sheathed metallic slings should be used for handling the tubulars.

2.4


3.

RIG-SITE PREPARATION AND INSPECTION

3.1

The BP Drilling Supervisor will conduct a pre-job meeting with the rig crew and casing/tubing running crew to ensure that the proper handling and running procedures are fully understood.

3.2

On arrival at the rig site, tubulars should be carefully unloaded onto the pipe-deck. DO NOT DROP THE PIPE.

3.3

The pipe-deck should be lined with wood, or a similar non-metallic material. Care should be taken at all stages to prevent tubulars having any impact with metal objects.

3.4

Tubulars should be removed individually from transportation racks using polymer slings. Steel slings should not be used as these may damage the tubular.

3.5

Layout one layer of tubulars on the wooden lined pipe-deck.

3.6

Remove transportation protectors (use only wooden or plastic mallets).

3.7

Drift, measure and tally each joint (using a non-metallic drift).

3.8

Thoroughly steam clean and dry both box and pin ends. Do not use diesel or paraffin as a cleaning agent.

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3.9

On no account should the threads be cleaned with a wire brush. Wire brushing may remove or damage the surface coating. Use a non-metallic bristle brush.

3.10

Visually inspect pipe body, thread, thread coating and the seal areas for any sign of corrosion or damage. Minor damage away from the seal area may be repairable by filing. Any joint that fails the inspection should be rejected. The rejected joint should be clearly marked with a red band and the reason for rejection should be painted on the joint. Rejected joints are to have clean protectors reapplied and joints are to be segregated.

3.11

Apply light coating of Moly Disulphide (MOS2) for VAM "ACE" connections (not necessary for NK3SB connections).

Note: This should be completed as soon as possible after steam cleaning, while casing is warm, to help curing. 3.12

Steam clean transportation protectors and dry and re-apply to tubing.

3.13

Layout subsequent layers of tubing ensuring wooden supports between each layer and repeat step 3.5 until all joints have been laid out.

Note: Ensure that when racking tubulars (for 7" no more than 5 rows high) comply with API recommendations. 4.

PRE-JOB CHECKS

4.1

A wooden or rubber lining should be installed on the catwalk and the Vee Door. If this is not possible, tubulars will have to be lifted directly into the Vee Door by the crane.

4.2

In order to ensure all handling tools and tong jaw dies conform to the exacting requirements of high chrome tubing, it is recommended that a single source take responsibility to supply the complete package.

4.3

Check all handling and make-up equipment is on site and meets the specifications laid down in Salvesen Tubular Services recommended equipment list. All tong jaws and handling tool dies shall be checked by the Salvesen Service Supervisor to ensure they are the specified type for running high chrome tubulars, i.e: a)

Tongs - Fine toothed or smooth faced wrap around type.

b)

Handling Tools - Varco flat topped (0.01") dies.

4.4

All handling tools should be function tested on the tubulars to ensure correct fit and operation.

4.5

Salvesen Service Supervisor should agree with the Company Representative the parameters to be used, i.e. torque figures and make-up speeds. For high chrome tubulars make-up speeds should be no more than 8 rpm (high speed) and 1.5 rpm (low speed).

4.6

All power equipment (power units, power tongs, Salvos) should be rigged up, calibrated to job parameters and function tested.

5.

RUNNING AND MAKE-UP

5.1

Prior to commencing running operations, the BP Drilling Supervisor should hold a meeting with the Well Services Supervisor, drill crew and Salvesen personnel on the rig floor. This should cover the exact handling and make-up procedure to be used, identify hazards and reinforce safety awareness.

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Note: a) Care should be taken at all stages to prevent impact of tubulars against any metal objects. b)

Non-metallic polymer slings should be used for lifting all single joints of tubing.

c)

All handling tool dies should be kept clean and changed if necessary.

d)

Tong dies should be inspected after every fifth make-up or break-out and should be replaced if flats in excess of 0.5mm appear on more than 10% of the teeth, or severe marking of the tubulars is identified.

e)

Ensure correct size of tong is used (i.e. 7 5/8" tong for 7", and 5 1/2" tong for 5 1/2"/4 1/2" tubing) and tong correctly balanced.

f)

A stabber is recommended for all tubulars.

5.2

Pick up individual joint using polymer slings and carefully lay onto the wood lined catwalk.

5.3

The tubular can then be picked up in either of the following ways (dependent upon rig design):a)

Latch internal coated single joint elevator (attached to rig floor tugger) onto the joint and transfer along wooden or rubber surfaces of catwalk and Vee Door to rig floor.

b)

Pick up with crane, using two polymer slings, and transfer joint along catwalk and through Vee Door to drill floor. Carefully latch internal coated single joint elevator onto the joint and slacken off weight taken by the crane.

c)

Pick up with crane, using two polymer slings and set down joint directly in the Vee Door. Carefully latch internal coated single joint elevator onto the joint and slacken off weight taken by the crane.

Note: It is assumed at this point a downhole packer of sub-assembly has been placed in the rotary table ready for the first joint of tubing. The procedure for such sub-assemblies is exactly the same, extreme care shall be exercised. 5.4

With the joint in the Vee Door, remove the box end protector and visually inspect the thread and seals for mechanical damage.

5.5

The single joint elevator attached to the blocks should be carefully fitted and the joint slowly raised to the vertical position with the pin end restrained away from the rotary centre line.

5.6

With the tubular suspended in the single joint elevator, ensure pin end is held a safe working distance from the rotary table, remove protector and inspect threads and seals in accordance with manufacturer's instructions on the pin to ensure no damage has occurred prior to make-up.

5.7

With a clean, soft, 2" paintbrush, apply an even coating of mixed and heated thread compound, from the Dopemaster, to the pin and box joint in the table. Ensure dope is applied as recommended by thread manufacturers. The dope should form an even coating with the threadform still clearly visible through the coating.

Note: If insufficient thread compound is applied, high shoulder torque may be recorded or even galling of threads may result. If excessive thread compound is applied, it may and most probably will be extruded into the bore which may cause problems during wirelining. 5.8

A stab-in guide should be fitted to the box end of the joint in the rotary table and the joint of tubing hanging in the single joint elevator shall be carefully moved into position with the pin end held over the stab-in guide.

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5.9

This joint shall be slowly lowered until pin threads are seen to contact the box threads.

5.10

A clear signal should be given to the technician on the stabbing board that the pin and box ends have been engaged correctly and to align the joint for efficient make-up.

Note: A polymer strap wrench shall be fitted by a member of the drill crew. With the assistance of the technician on the stabbing board, the joint should be slowly walked in by hand all the way to the handtight position. If correct thread engagement has not been achieved, the pin should be rotated anti-clockwise until pin drops and engages correctly. 5.11

When the connection has reached the hand-tight position, the power tong can be placed on the pipe. Great care should be taken to ensure that the tong is positioned on the tubing without any part of the tong or back-up impacting the tubing wall.

5.12

The back-up shall be activated to grip the tubing, care should be taken to ensure that the back-up jaws are correctly positioned and are gripping the tubing evenly.

5.13

The tong can now be activated to grip the tubing and the make-up can proceed using the Speedmaster control on the tong.

5.14

The Salvo will monitor the make-up as it takes place, if accepted the single joint elevator and power tong should be removed at this point and operations will continue as of step 5.16.

5.15

If make-up is aborted for any reason, refer to Section 6, Pulling Out.

5.16

After a satisfactory Torque Turn Graph has been recorded and accepted with the tally number logged on the Salvo, slowly lower the main elevator and carefully position it over the tubing string. The elevator can now be latched.

5.17

Raise the string a short distance so as to enable the hand slips to be removed or the spider to be unlatched. (During the running of the initial joints, a safety clamp may be required; if so this should be removed.)

5.18

Slowly lower the string until the box end is in the correct position for the next connection to be made up. Do not set the slips with the string moving.

5.19

Place the hand slips in position or set the spider and slowly lower the string until the slips engage. Until there is sufficient weight on the string (10 - 20 joints) a safety clamp should be used.

5.20

Carefully remove or unlatch the elevator; if a door type elevator is being used, care should be taken to ensure that the elevator does not impact the tubing wall.

5.21

Repeat the above procedure until the final number of joints have been run.

6.

PULLING OUT If the make-up is aborted for any reason or if the connection requires to be broken out and made up a second time, this procedure should be followed.

6.1

Re-fit the single joint elevator.

6.2

Position tong back-up jaws across coupling. Slowly rotate the tong in the break-out direction until the torque has dropped below the reference level.

6.3

Re-fit the polymer strap wrench.

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6.4

Slowly walk out the connection with the assistance of the technician on the stabbing board aligning the joint correctly.

6.5

Do not apply any force to pull the pin from the box. Slowly raise the tubing joint only when the threads have fully disengaged.

6.6

Thoroughly clean both the pin and box prior to inspection, ensuring the pin end is held a safe working distance away from the rotary table.

6.7

If no problems are found with either the threads or the seals, continue with the drying, doping and rerunning of the connection as previously described.

6.8

If the joint has to be laid out, apply storage compound, clean transportation protectors and carefully lift back to the Vee Door, then lift or lower to the pipe deck area. The drill crews should clearly identify the rejected joint by marking with red paint "Reject" and indicate thread damage (TD) or seal damage (SD) and place to one side.

7.

POST JOB CHECKS

7.1

At the end of the job, the Salvesen Services Supervisor shall check the number and state of joints left on deck, i.e. good joints or rejects, including pup joints and accessories.

7.2

He shall ensure all left over joints are doped and protected.

7.3

Check all rejects are red banded and marked "Reject" and indicate damage.

7.4

Ensure all pup joints and accessories are doped and protected.

7.5

After the job is finished, the Salvesen Services Supervisor will complete all relevant paperwork and get it signed by the BP Drilling Supervisor or Well Services Supervisor. The Salvesen Services Supervisor should ensure that all equipment is rigged down and boxed and liaise with the BP Drilling Supervisor or Well Services Supervisor to see if it is being back-loaded.

7.6

If the crew and equipment are staying at the wellsite, then the equipment should be serviced and any extra equipment or spares ordered prior to the next job.

7.7

The tubulars should be back-loaded as soon as possible after completion of the job to minimise exposure to the environment. Use tubular rack or boxes as for transportation to the rig.



Index Prefixes 0000


1000

Drilling

2000

Casing and Tubing

3000

Cementing

4000

Drilling Fluids

5000


6000


7000

Well Evaluation

8000






Section

Description

3000

CEMENTING

3000/GEN

Cementing - General

3010/GEN

Cementing - Responsibilities

3020/GEN

Cementing - Pre-Job Checklist

3030/GEN

Cementing - Operations Checklist

3040/GEN

Cementing - Programme Checklist

3050/GEN

Cementing - Cement and Additives

3100/JAK

30" Cementation Using Stab-In Technique

3100/FIX

30" Cementation - Fixed Installations Run/Drill/Run/Cement

3100/SEM

30" Conductor and Top-Up Cementations

3200/SEM

20"/18.5/8" Cementation

3200/FIX

20"/18.5/8" Cementation Using Stab-In Technique

3210/FIX

20"/18.5/8" Cementation Using a Casing Pack-Off

3300/GEN

13.3/8" Cementation

3350/GEN

9.5/8" Cementation

3450/GEN

7" Liner Cementation and Clean-Out

3500/GEN

5"/4.1/2" Liner Cementation and Clean-Out

3550/GEN

Liner Pressure Testing


SUBJECT:


3560/GEN

Liner Drawdown Testing

3600/GEN

Cement Plugs

3610/GEN

Parabow Cementing Tool

3650/GEN

Squeeze Cementing

3750/GEN

Losses During Cementation

3780/GEN

Cement Contaminated Oil Based Mud

3800/GEN

Evaluation of Primary Cementing


SUBJECT:


3100/AME

30"/27" Conductor Cementation

3200/AME

20" Cementation Using Stab-In Technique - Amethyst

3200/WYF

18.5/8" Cementation Using an Inner String Method - Wytch Farm

3300/AME

13.3/8" Cementation - Amethyst

3310/WYF

13.3/8" Cementation Using an Inner String Method - Wytch Farm

3350/AME

9.5/8" Cementation - Amethyst

3350/WYF

9.5/8" Two Stage Cementation - Wytch Farm

3450/AME

7" Liner Cementation and Clean-Out - Amethyst

3500/AME

4.1/2" Liner Cementation and Clean-Out - Amethyst

3500/WYF

5.1/2" Liner Cementation and Displacement of Liner and 9.5/8" - Wytch Farm

3510/WYF

Liner Cement Cleanout - Wytch Farm

3520/WYF

Post Perforation Cleanout - Wytch Farm


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CEMENTING: GENERAL

The following cementing section provides details of cements, additives, slurry designs and cementing procedures. Particular attention should be paid to the section on responsibilities and to the handling and packaging of materials for testing. The Drilling Supervisor/Engineer should consult the cementing flowchart, page 4. The flowchart will assist the planning and successful execution of the cement job. It is standard practice to use a cementing kelly for all SSR jobs. This assists in handling the surface equipment and allows the casing running tool to be backed out with the rotary.

1.2

Planning The success of a cement job will be dependent upon the Drilling Representatives supervision of 3 main areas: a) b) c)

Inspection and testing of equipment. Calculations. Pre-planning of contingency operations.

These are outlined in Section 3010/GEN. Sending in correctly packaged and labelled samples of cement, mix water and additives for testing well in advance of the cement job is crucial to the success of the operation (see Section 3040/GEN). 1.3

Calculations/Bulk Volumes By tradition all cement slurry calculations are referenced to the unit 1 sack of cement. This unit is 94 lb of cement and 1 cubic foot of packed volume. However, when aereated in a bulk system the average density is usually found to be +/- 75 lb/cu ft. Silo contents are usually derived from volume measurements and as such should be equated to the lower density figure to calculate the number of sacks available.

1.4

Cement Excesses For casing cementations, it is normal in most circumstances to use an excess on top of the caliper volume. For liner cementations, it is normal to use 30% excess on the caliper volume with (in some cases) an extra 10 bbl or 100 - 150m liner lap volume.

1.5

Blended Cements The blended cements commonly used are Class G cement mixed with 35% BWOC of silica flour and Class G cement with 8% BWOC bentonite. The bulk density of silica flour is 70 lb/cu ft. 1 sack of cement is equivalent to 35% silica

94 lb 33 lb

= 1 cu ft = 0.47 cu ft

Nett bulk density is 86.4 lb/cu ft for the blend. The bulk density of bentonite is 60 lb/cu ft. 1 sack of cement is equivalent to 8% bentonite

94 lb = 1 cu ft 7.5 lb = 0.13 cu ft

Nett bulk density is 89.8 lb/cu ft for the blend.

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CEMENTING: GENERAL

Notes: Aerated bulk density of cement and blends is less than the Nett bulk density. A bulk tank will start venting at 80% of tank volume. Aerated bulk density is therefore approximately 80% of nett bulk density. For example, using G + 35% silica flour, Aerated bulk density = 0.8 x 86.4 = 69 lb/cu ft. Using another example, a 1000 cu ft silo will only take 800 sks of neat G (800 cu ft with the air off). For slurry calculations all concentrations (gallons/sk) and yield figures refer only to the cement in the blend. So if we require 750 cu ft of slurry having a yield 1.48 cu ft/sk then we required 507 sacks of cement. For a blend of cement plus silica flour 507 sacks cement is contained in 507 x 1.47 = 745 cu ft of blend (at a bulk density of 86.4 lb/cu ft). Correcting for the effect of aereation the required silo capacity for the above case would thus be +/930 cu ft. 1.6

Standard Casing Volumes and Dimensions Refer to Section 2800/GEN.

1.7

Cement Additives Cement additives are almost without exception used in a liquid form and metered into the slurry mix via the liquid additive system on the cement unit, the concentration (gallons per sack) being converted into gallons per (10 bbl) displacement tank of mix water.

Note: The capacity of most cement unit displacement tanks is greater than 10 bbl. The true volume should be checked prior to the first fill to avoid dilution of liquid additives. All cement additives to be used in a forthcoming cementing operation must be physically checked using a hydrometer. To prepare the mixwater in the case of prehydrated bentonite, prehydrate all the bentonite in a volume of freshwater equivalent to half the total mixwater volume, then after hydration (up to 4 hours) top up with seawater to the total volume. Mixwater and additive volumes will be included in the cementing telex to the rig. 1.8

Cement Tests The following cement tests are normally performed and results reported in the cement telex. a) b) c) d) e)

Thickening time (70 bcs and 100 bcs). Operating free water (ml). Compressive strength (8 hrs and 24 hrs in PSI). Rheology (Fann). API fluid loss (ml/30 min).

Total mix fluid requirement (gal/sk) and slurry yield (cu ft/sk) are also reported. Further tests may be performed to investigate gellation tendencies.

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CEMENTING: GENERAL

Subsea Release Cementing System Ensure an SSR top plug only is used. This should be shear pinned to the SSR mandrel to give a shear out pressure of +/- 1850 psi (for 13 3/8” and 9 5/8” size). Place a kelly cock below the dart release assembly at the rig floor and test the whole assembly including the cement line to 1000 psi above plug bump pressure. Check that the wiper plug is properly shear pinned and that a dart has been correctly loaded and is the correct size for the drill pipe in use. Ensure that the DP landing string has been drifted to the correct diameter for the dart. The sequence of events when cementing with SSR equipment is as follows: a)

Pump spacer.

b)

Mix and pump the required volume of cement slurry.

c)

With the cement line to the rig floor full of cement, release the pump down dart.

d)

Pump 2-3 bbl of water (or base oil if OBM is being used) to clear the cementing line of cement, followed by the required volume of mud to latch the dart into the SSR wiper plug. This should be done at 4-6 BPM to avoid bypassing the dart.

e)

Observe the wiper plug shear, change lines at the rig floor and continue the displacement with the rig pump.

The complete cementing operation, including wiper plug shear, is to be, recorded on an ancillary pressure recorder. 1.10

Surface Release Cementing System For cementations on fixed installations and on semi-submersibles using full bore wellhead running equipment, a top and bottom cement plug is to be installed.

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CEMENTING: GENERAL

DRILLING MANUAL SECTION

PLANNING Ensure all Team Members are aware/ understand their responsibilities

3010

Complete Pre-Job Checklist

3020

Complete Programme Checklist

3040

Complete Planning Sections in Manual for relevant Job Type

3100 - 3650

OPERATION

Drilling Programme

Follow detailed instructions issued by Drilling Supervisor

EVALUATION

Follow detailed instructions issued by Drilling Supervisor

Operations Checklist

3030

Relevant Job Section

3100 - 3650

Drilling Programme Relevant Job Section

3100 - 3650

Primary Cement Evaluation

3800

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CEMENTING: RESPONSIBILITIES

Drilling Contractor The drilling contractor is responsible for operating and in some cases maintaining the bulk supply and mixing systems. He is also responsible for providing personnel for loading and backloading of supplies and equipment. He will assist with sampling prior to and during the cement job. The following minimum checks and procedures are to be performed: i)

Air up all tanks the day before the cement job, check for leaks. Carry out repairs immediately.

ii)

Pressure test and physically check all air supply lines and valves in the bulk system.

iii)

Start up and check compressors, check alternative air supply is available immediately the primary system fails.

iv)

Ensure surge tank is clean internally, all valves and vents working.

v)

Blow through all lines. Ensure dry air is vented and lines are clear.

vi)

Prior to filling the pods from the supply boat, ensure all lines from the boat to pods are blown through until dry air is vented.

Note: If at any time damp air is found venting, either from the supply boat of on the pre-cementing inspection the cause must be established and corrective action taken.

1.2

vii)

Time the surge tank filling rate. Compare with previous filling rates and normal mixing rates.

viii)

Ensure air pressure can be adequately maintained.

ix)

Prior to filling storage pods from the supply boats, open the pod and physically check for debris/rocks etc.

x)

Sign a check list when all the above inspections have been completed.

xi)

Purge all lines immediately upon completion of a cement job until dry air is vented.

Offshore Cement Operator Photostat this Section 1.2 - cementer to check each item and sign off pages checked. Return to Drilling Supervisor/Engineer signed and dated pages. a)

The cement operator’s duties are: i)

Maintain and operate the cementing installation and all associated equipment on the rig to the highest standards of reliability, and ensure that the unit has valid certification, including certification for any densitometer with a radio-active source.

ii)

Record stock levels of cement and additives and maintain quality control and physically check all stocks on a weekly basis and prior to any cementing operation. Liquid additives MUST be checked by use of a hydrometer. Maintain adequate spare parts and consumables to support the offshore operations. Maintain a log book of all materials used and delivered.

iii)

Carry out individual cement calculations and verify calculations performed by the wellsite drilling engineer and the Drilling Supervisor.

iv)

Perform the cement job as per the programme specified by the company, including the use of liquid additive dispensing units and data recording devices.

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v)

Obtain representative samples of cements and additives and forward these in good time for laboratory testing, properly packaged.

vi)

Check the cement unit and equipment and ensure the following: Unit and lines are pressure tested to minimum 1000 psi above casing test pressure using a chart recorder. Unit displacement tank barrel scale is accurate. Displacement tank valves do not leak, and are easily operable. Low pressure mixing system is flushed through. Packings on mix pumps are operable. Pressure on mix pumps is more than adequate for mixing. Jets in mixer are correct. Packings on HP pumps are operable. High pressure mixing system is flushed through. Correct jets are available for high pressure mixing. Bypass valve on mix manifold is working. Bypass on mixer is open (manually). Engine oil and water are at correct levels. Oil in pumps is at correct level. Hoses are serviceable. Hopper is serviceable. Cement head, i.e. valves, threads, indicators and plug locator pins are all operable. Liquid additive system pumps, lines, gauging rates are sufficient to meet mixing requirements. Physically check that the volumes of liquid additives are sufficient to provide 100% in excess of job requirements. Water supply rate to displacement tanks or batch tank exceeds maximum estimated requirement. Batch mixer is operating correctly. Operator is to sign a check list prior to casing being run confirming all checks satisfactorily completed. If operator doubts the high pressure mixing system he should mix 50 sks overboard to prove the system.

1.3

Offshore Drilling Engineer (if present) i)

Ensure cement, additive and mixwater samples are sent in correctly marked and packaged.

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ii)

Collect samples during the cement job.

iii)

Confirm stock levels of cement and additives; must carry out a physical check on stock. Minimum level is for 2 jobs.

iv)

Collate downhole temperature data as a check on cement slurry design. Compare to test temperature.

v)

Witness and check quality control of caliper logs.

vi)

Compute slurry volumes from caliper.

vii)

Prepare individual calculations for the cement job. Compare results with the separate calculations carried out by the Drilling Supervisor and cementer.

viii)

Verify and monitor mixwater volumes, displacement volumes and pressure during the cement job.

ix)

Supervise preparation of spacers, cement and additives. Ensure cement is fluffed as per recommended procedure.

x)

Prepare all cementation reports.

Operations Drilling Engineer (Onshore) i)

Ensure cement, mixwater and additive samples are dispatched in good time to the service company for testing.

ii)

Verify the cementing telex is correct and meets the requirement of the planned cementing operation.

iii)

Ensure the cementing telex is forwarded to the installation in good time for the operation.

Drilling Supervisor i)

Inform the Mud Loggers and Driller of: a)

The volume of each type of mix water to be used for both lead and tail cement jobs.

b)

From which mud pit each type of mix water will be drawn.

c)

The expected gain, per barrel of mix water blended with cement, for both lead and tail slurries.

d)

The expected total volume of returns during the cement job and the expected overall increase in pit volume.

ii)

Supervise the DE, cementers and drilling contractor in the performance of their duties.

iii)

Prepare individual calculations for the cement job.

iv)

Approve all reports, worksheets and job tickets.

v)

Co-ordinate the execution of the cement job. Ensure that all relevant personnel are issued with a detailed programme of the cement job, highlighting individual responsibilities. The detailed programme must include volumes, pressures and pump rates for the cementing and displacing operations. Contingency plans must also be drawn up for any equipment failure etc. Procedures must be written to cover alternative mix water supply, rig pump failure, alternative mixwater and displacement valve measurement and procedures if predicted pressures are exceeded or return volumes insufficient to maintain displacement with mud.

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CEMENTING: RESPONSIBILITIES Note: Ensure that the operation checklist is completed prior to all jobs. This is regardless of any separate checklists generated by the Cementing Company. The checklist should be retained in the offshore Well File.

1.6

Mud Engineer and Mud Loggers i)

Mud Engineer is to check the mix-water for contamination.

ii)

Mud Engineer is to ensure that a sufficient volume of mud is available on the surface prior to commencement of the cementation.

iii)

Mud Loggers/Mud Engineers are to monitor pit volumes throughout the cementation.

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CEMENTING: PRE-JOB CHECKLIST

The operation check list is to be used and referred to at all times when planning and preparing for cementing operations. 1.

Ensure the following samples are sent to the cementing contractor prior to cement job for lab testing: Cement from each silo Mix water Liquid additives

10 kg 1 gal 500 ml

2.

Ensure extrapolated log temperatures compare with cement test temperature. Ensure thickening time is adequate for anticipated duration of the job.

3.

Ensure calipers have been calibrated inside previous casing shoe. Compare different calipers with each other. Check for any off scale washouts on the caliper.

4.

The mud may require conditioning during the check trip prior to running casing to reduce gels and viscosity. Ensure YP is reduced to below 15 lb/100 sqft and gels to below 10/20 lbs/100 sqft for oil muds and below 5/10 lb/100 sqft for water based muds.

5.

Calculate any reduction in hydrostatic head due to cement spacers. Check overbalance. Assume gauge hole. Ensure overbalance is maintained through all stages of the job.

6.

Ensure separate lines are available from LAS system for extender and retarder or any additives which react with each other (see Figure 1 for diagram of idealised LAS system).

7.

Inhibit any water based mud or spacer to be left in the annulus unless the well is to be abandoned.

8.

Beware of gel strength development in slurries particularly at elevated temperatures in the range of 180 - 250 deg F. Be particularly concerned to minimise unnecessary shutdowns during mixing and pumping.

9.

Check maximum expected ECD against shoe strength.

10.

Ensure sufficient materials on board for double the estimated quantity, providing 100% contingency.

11.

Fluffing of the cement can lead to degradation and should be kept to a minimum. Fluff cement immediately after topping up the silo just prior to collecting a sample, once a week while on the rig and immediately prior to the cement job. Do not top up silo again after collecting samples. Ensure that sufficient cement tanks are prepared and pressured up.

12.

Ensure adequate tank space is available for returns and allow for excess returns due to differential pressures.

13.

Ensure that a pressurised mud balance for determining densities of critical slurries is available. Many slurries will entrain air which will cause them to weigh much less than downhole density in a standard mud balance.

14.

Ensure mud pump fluid ends are inspected prior to the cement job. As a bare minimum all the valve pots should be removed and the valves/springs/ seats checked for wear.

15.

Ensure that all necessary equipment is on board and checked out. In particular, when surface release cement plugs are to be used, check the condition of the surface cement head (Figure 2).

16.

Ensure that the cement unit and all lines to the rig floor are flushed through and pressure tested as specified several hours before cementing is due to take place.

17.

Check the mix water transfer line for leaks.

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CEMENTING: PRE-JOB CHECKLIST

Note: All other valves leading from this line should be locked closed. 18.

Prehydrate bentonite and other additives to the mix water in good time prior to the cement job.

19.

Check the concentration level of all pre-mixed salt water by titration against silver nitrate. The measured concentration may differ from the calculated concentration due to the temperature of the water or effectiveness of the mixing.

20.

Ensure all cement additives to be used are physically checked and that liquid additive density is checked by use of a hydrometer.

21.

Ensure lab test results are on the rig.

22.

Ensure cementer has completed and signed off photostated Section 3010/GEN 1.2 - Offshore Cement Operator Duties. Keep signed copies in Well File.

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CEMENTING: PRE-JOB CHECKLIST FIGURE 1 IDEALISED L.A.S. SYSTEM

BULK TANK

BULK TANK

BULK TANK

BULK TANK

RETARDER

FLUID LOSS ADDITIVE

EXTENDER

FRICTION REDUCER

EXTENDER

FRICTION REDUCER

30 GALL MEASURING TANK


RETARDER

FLUID LOSS



10 BBL MIX TANK

10 BBL MIX TANK

NB. ALWAYS ENSURE SEPARATE DEDICATED LINES FOR EXTENDER & RETARDER 2179 / 81

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CEMENTING: PRE-JOB CHECKLIST FIGURE 2

'O' RING

PIPE SEALS VALVE

PIPE SEALS VALVE

PLUG RELEASE PIPE SEALS VALVE

PLUG RELEASE

PIPE SEALS

'O' RING

QUICK COUPLING

SURFACE CEMENT HEAD CHECK POINTS 2179/82

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CEMENTING: OPERATIONS CHECKLIST

Both the Driller and the Mud Engineer are to prepare pit and flowlines for the expected total returns. 1.

The system must be prepared to accept the total volume returned (= bbls of slurry and spacers to be pumped) into one pit only.

2.

Circulation system, including the sandtrap, should be complete and full of mud.

2.

The Driller and the Mud Loggers are to record the volumes in each individual pit and the total volume in the pits.

3.

After the mud pits have been prepared, no mud is to be transferred or dumped and no ballast control movements are to take place without prior permission from the BP Drilling Supervisor.

4.

The BP Supervisor/DE is to inform the Mud Loggers and the Driller at the start of mixing cement.

5.

Ensure the following samples are taken at regular intervals during the cement job in case of problems: Cement from Surge Tank Actual Mix Water with Additives* Water (Drill Water/Sea Water) Individual Liquid Additives Slurry Samples

10 kg 1 gal 1 gal 500 ml 5-10 cups

Check density of the liquid additives prior to use.

Note: a) Mixwater samples should be collected at the beginning, middle and end of the lead and tail slurry. b) Retain the slurry samples for observation. 6.

The BP Supervisor/DE is to inform the Mud Loggers and Driller when changing from the lead to the tail cement slurry and at the end of pumping cement.

7.

Maintain plot of displacement vs top of cement and also position of top plug. Compare theoretical and actual pressures. Note any losses during the cementation. Do not confuse U-tubing with losses. Record pressure prior to bumping the top plug and calculate theoretical top of cement.

8.

The BP Supervisor/DE is to inform both the Mud Loggers and the Driller periodically of the amounts of mix water used.

9.

Ensure cement operator changes displacement tanks correctly to minimise error in slurry or displacement volumes.

10.

Leave mixing tub full of the proper required cement slurry at the conclusion of mixing. Avoid the possibility of pumping diluted cement or even water into casing before the top plug is released.

11.

Ascertain that the correct pit(s) have been lined up to the mudpumps and put a short pressure test on the cement head/valve after lining up to ensure the pump has suction.

12.

Physically ascertain the amount of fluid pumped from the pits, and check that the pits are dropping by the requisite amount during the displacement. The pump stroke counters will not be relied on as the only means of discerning the volume of displacement pumped.

13.

If more than one pit volume is required equalise across two pits and pump the displacement, if that is not possible then displace a volume from one pit, stop the pumps, line up to the second pit and complete the displacement.

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CEMENTING: OPERATIONS CHECKLIST

14.

Displace the cement with mud. Determine the displacement volume, pump strokes and pumping time at which the displacement rate should be reduced prior to bumping the plugs. Displace cement at maximum rate allowable from pressure consideration unless advised otherwise.

15.

The active pit gain is to be monitored continuously during cementing. Expect additional return volumes during mixing and reduced return rates during initial displacing. Ensure any losses are noted.

16.

Displace from the cementing unit in the following cases: a)

When no rig pumps available. Control volume by measuring from mud tanks as well as cement unit displacement tanks.

b)

When placing cement plugs or cementing through drill pipe.

c)

Liner cementations.

17.

If rig pump is used, have cementer’s pump unit ready to take over to bump the plugs in case the pressure becomes excessive. Record all mixing, displacing, bumping, opening/closing of D.V. collars, etc on pressure chart.

18.

The Mud Loggers/Driller are to record the total volume in the pits and inform the BP Supervisor/DE of the volume gained (or lost) during the entire cement job.

19.

After bumping top plug, release pressure, measure returns and check for backflow.

20.

If there is backflow, pump back the amount of backflow only and repressure the casing. If there is still backflow, wait until the cement is hard before repeating the test.

21.

Pressure test casing immediately after bump (15 min API).

22.

If float equipment fails and/or pressure is held on the casing, a pressure gauge should be installed on the cement head so that the required pressure can be maintained and excessive pressure bled off periodically. In this case the pressure left on must not exceed the observed differential pressure between mud and cement.

23.

On dual stage jobs, close the D.V. with a pump rate of 8 bbls/min and build up to a 1000 psi pressure above the total of opening pressure of the D.V. collar and the pressure differential of cement and mud. Keep the pump strokes constant until this closing pressure is reached. Mud inertia is used to close stage collar.

Note: When first stage is bumped, measure the amount of fluid bled back so as to have an idea of the amount bled back on the second stage. This is in case difficulties are experienced.

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CEMENTING: PROGRAMME CHECKLIST

The programme check list is to be referred to at all times when planning cementing operations. 1.

The specifications of a cement job given in the drilling programme are merely outlines. The actual cementing programme and design of the job will be determined from the laboratory tests of the actual rig samples. The results of these tests will be forwarded to the Drilling Supervisor on a cement telex.

2.

The specifications given in the drilling programme should be checked against actual circumstances of the well.

3.

Check the programmed TOC covers all hydrocarbon bearing or overpressured permeable intervals.

4.

Ensure a caliper is available where required to determine cement volumes. Record caliper type.

5.

Ensure the specified slurry weight is appropriate given, the existing mud weight and length of cement column.

6.

Ensure the thickening time of the slurry is greater than the planned job time, including mixing. As a general guide, the thickening time to 70 Bc at the BHCT should exceed the time to mix, pump and displace by a period of 1 to 2 hours.

7.

Ensure any apparent discrepancies between the drilling programme and the objectives of the cementation dictated by actual circumstances are fully discussed with the Drilling Superintendent well in advance of the job.

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CEMENT AND ADDITIVES

1.1

Functions of Cements

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CEMENTING: CEMENT AND ADDITIVES

1.

a) b) c) d) e) f) g) h) i) j)

Section

Bond the casing to the formation. Minimise the danger of blowouts from high pressure zones. Protect all producing zones. Seal off lost circulation zones or other troublesome formations before drilling ahead. Repair defective casing in some cases. Abandon non-producing formations. Isolate zones prior to production or fracturing. Re-inforcement and corrosion protection. Plug back to abandon or sidetrack a well. Isolate water producing intervals.

API Classification of Oil Well Class G Cement Class G cement is the standard cement used in UKCS operations. It is intended for use as a basic cement from surface to 8,000 ft as manufactured, or can be used with accelerators and retarders to cover a wide range of well depths and temperatures. No additions other than calcium sulphate or water, or both, shall be interground or blended with the clinker during manufacture of class G cement. Available in moderate and high (tentative) sulphate resistant types.

1.3

Cement Additives Various materials can be added to class G cement to tailor the cement properties to meet the actual well conditions (refer to Tables 1, 2, 3 and 4). The major additives are:

1.3.1

Accelerators (Table 2) Accelerators increase the rate of hydration whch occurs when cement comes into contact with water. Most highly ionic, inorganic compounds, such as sodium chloride and calcium chloride, are very good accelerators. a)

Calcium Chloride CaCl2 Calcium chloride always acts as an accelerator and is generally used at 2-3% BWOC. The cement companies also supply a CaCl2 as a liquid additive (0.4 gal/sk is equivalent to 2% BWOC).

Note: Solid calcium chloride can cause skin burns and severe irritation to eyes, nose and lungs. Close control of concentration is essential. Excess quantities can result in very rapid setting. b)

Sodium Chloride NaCl Sodium chloride only acts as an accelerator at concentrations up to 15% by weight of water. It will behave as a retarder at concentrations over 20%. It is not so effective as calcium chloride.

c)

Seawater North Sea water contains ca. 20,000 ppm chlorides and will accelerate the setting of cement to an equivalent level of 1% CaCl2 BWOC.

1.3.2

Retarders (Table 1) Retarders are used to delay the setting time of cement slurries at higher temperatures. They slow down the rate of the cement - water reaction by absorbing onto the surface of the cement particles or by

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forming a chelation complex. It is extremely important that the cement slurry is fully sheared and dispersed to provide the full surface area for adsorption. Lignosulphonates, sugar derivatives and occasionally cellulose derivatives are widely used as retarders. Lignosulphonate retarders tend to reduce the viscosity of the slurry while the cellulose and sugar based regarders tend to increase the viscosity. Retarders also tend to cause foaming and require the use of a defoamer. At a particular temperature, retarder concentration is directly proportional to thickening time only over a limited range. At higher concentrations, even a small additional amount of retarder, less than 0.05 gal/sk, can cause a large increase in thickening time. When designing a cement slurry, the effect of additing an additional small amount of retarder should be checked. Compressive strength should also be checked to ensure the retarder has not totally destroyed any development of compessive strength. a)

Low Temperature Retarders Calcium Lignosulphonates are generally used up to 180 - 200 deg F. Occasionally they are used up to 220 - 230 deg F, however, above 200 deg F, unpredictable results can be obtained and gellation of the slurries can be a problem.

b)

Moderate Temperature Retarders This temperature range is usually taken as 100 - 250 deg F and modified calcium lignosulphonates are used.

c)

High Temperature Retarders In general, sugar derivatives are used in the range 250 - 300 deg F. They can be used at temperatures as low as 180 - 200 deg F, however, the very low concentrations required would make the thickening time too sensitive. At temperatures greater than 300 deg F, speciality additives are used. Halliburton use Component R in conjunction with their moderate temperature range retarder and Dowell use D-28, an organic acid plus sugar derivative.

Note: The temperature ranges for low, moderate and high temperature retarders overlap. In the overlap ranges, considerable testing may be required to establish which retarder gives the most reliable slurry design. There is no such thing as retarder predictability. Slurries must always be tested in the laboratory using representative cement, water and additive samples. 1.3.3

Dispersants (Table 3) Dispersants reduce the apparent viscosity of the slurry and allow higher pump rates to be used for the same pressure drop. Compatibility of dispersants with the other cement additives is to be checked. The apparent viscosity can actually be increased by the addition of some dispersants when fluid loss additives are being used. Certain combinations of dispersants and fluid loss additives may also cause an increase in free water. Careful laboratory testing is required to ensure compatibility. There is no need to use a dispersant in standard 30" and 20" casings. Dispersants are only required in 13 3/8" and 9 5/8" strings if the casing is set deep, and may only be required in the liner slurry.

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DRILLING MANUAL SUBJECT: 1.3.4

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Fluid Loss Additives (Table 2) The mechanism of fluid loss control in cement is not fully understood. It is presumed that the additive acts as a bridging agent between discrete cement particles causing a blockage of the pore spaces. The fluid loss additive minimises the dehydration or loss of water to porous zones. This helps to achieve a uniform water-solids ratio which will maintain constant properties and viscosity. It is generally accepted that a fluid loss of below +/- 100 ml/30 mins is sufficient for most jobs, however, this may be reduced to +\- 50 ml/30 mins across highly permeable zones or during the setting of cement plugs. The fluid loss of a squeeze cement slurry should be as low as practicable. It is sometimes necessary to cement a high secondary objective, whch is highly porous, with an extended slurry in 9 5/8" casing. A low fluid loss is difficult to achieve even with the 13.6 ppg slurry weight necessary to achieve a reasonable compressive strength and in this case, fluid loss can be relaxed to +/- 200 mls/30 mins. Most fluid loss additives are based upon high molecular weight organic compounds which also tend to slightly retard the slurry. As mentioned previously with retarders, additive compatibility should be checked.

1.3.5

Density Adjusters a)

Heavy Weight Additives (Table 3) Occasionally it is necessary to add weighting material to the cement slurry to increase the density to withstand high formation pressures or to ensure efficient displacement of heavy muds. The additives should preferably be (i) as dense as possible, (ii) require minimum water, (iii) have no effect on compressive strength, (iv) have a uniform particle size range, (v) be chemically inert, (vi) not interfere with well logging. Care should be taken with dry blended material to ensure the dense material does not settle out. The blended material should be fluffed prior to the job. Guidelines will be provided at the time on how to check the quality of the particular blend being used. The cement slurry should also have enough viscosity to carry the additive. It is also possible to increase the density of the cement slurry to 17.5 ppg by using a reduced water-cement ratio. A dispersant would also have to be used to control the viscosity, however, viscosities would still tend to be higher than normal, and a practical upper limit can be considered to be 16.5 ppg. i)

Haematite (Iron Oxide) Haematite is generally accepted as the most common weighting agent for cement. It has a specific gravity of 4.95, is chemically inert and fulfills all of the requirements of a heavy weight additive allowing slurry weights of up to 20 ppg.

ii)

Ilmenite (Iron Titanium Oxide) Ilmenite has most of the benefits of haematite and is slightly less dense with a specific gravity of 4.45.

iii)

Salt Salt can be used to increase the density of cement slurries by up to 1 ppg, however, it is generally only used at such high concentrations to provide salt saturated slurries.

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Extenders (Table 3) Many formations cannot support a large column of cement at the high density of neat class G cement obtained when adding the recommended amount of water. In most cases, lightweight lead slurries can be used, which sacrifice some compessive strength, to provide a greater yield per sack of cement. This will in turn produce a more economical slurry. Lightweight slurries can be produced by adding low specific gravity solids such as hollow glass/ ceramic spheres. At present this method is not considered as common as the addition of materials which require large volumes of water such as bentonite or sodium silicate. In effect water is the real extender and the additive is used to prevent excessive free water forming. Extended slurries can be prone to excessive gel strength development if the pumps are shut down for any length of time. In some cases, the gel strengths can be so high that the fluid cannot be made to move again and it appears as if the cement has set. When the slurry design has been formulated, it can be checked for development of high gels by repeating the thickening time test. This time the paddles on the consistometer should be switched off for two minutes, 10 mins after the test temperature has reached equilibrium. The resultant gel strengths can then be measured. i)

Bentonite Bentonite can be used successfully either prehydrated or preblended. Preblended the concentration is 8% BWOC for a 13.2 ppg, 1.58 SG slurry. Prehydrated bentonite is used at a concentration of 2% BWOC or approximately 8 lb per bbl of mixwater. The actual percent of bentonite used should be determined by laboratory testing. The bentonite should be yielded in fresh water making up half the total of mixwater, seawater can be added to make up the full quantity after 2 - 4 hours.

ii)

Sodium Silicates Sodium silicates are used as chemical extenders in lightweight cement slurries. The standard lead slurry is mixed at a density of 13.0 ppg using 0.35 - 0.40 gal/sxs silicate extender. The exact concentration will depend on the actual produce used. The silicate extender reacts with calcium and magnesium which are present in the cement or seawater to form a gel. The silicate will be mixed in seawater to allow a controlled reaction to take place before it is added to the cement. The gel can absorb large quantities of water to produce lightweight slurries with minimum free water. As already states, extended slurries can become very viscous and develop high gel strengths. The flow properties of silicate slurries tend to be even less dependable at very light weights and at elevated temperatures, i.e. below 12.0 ppg and at temperatures above 185 deg F. Stringent laboratory testing is required for these conditions, where very lightweight extended slurries are required in 20" and 13 3/8" casings where the formations are particularly weak. Silicate extenders can react with certain lignosulphonate retarders if they come into contact prior to being added to the 10 bbl mixwater tank on the cement unit. If they come together in the manifold line, they can form a viscous sludge which can block the line. The LAS unit should be manifolded to provide separate lines for the silicate extender and the retarder.

1.3.6

Defoamers (Table 3) Certain cement additives such as retarders and fluid loss additives can cause foaming of the mixwater. A small concentration of defoamer can be added at 0.01 gal/sk to control the foam.

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Retrogressive Strength Additives (Table 4) Class G can undergo thermal degradation at temperatures greater than 230 deg F resulting in a loss of compressive strength and an increase in permeability. In extreme cases, the cement may crumble entirely with time. The cement can be made more stable to high temperature by blending the cement with silica. Silica is available in two mesh sizes as silica sand (80 - 200 mesh) and silica flour (350 mesh). The choice of mesh size is often determined by considering the effect on rheology. Silica flour is mainly used for dry blending at a concentration of 35% BWOC.

1.3.8

Lost Circulation Material Lost circulation can be a problem in some wells where whole fluid is lost to the formation as opposed to filtrate loss in a permeable zone. This may occur in fractured or cavernous formations as well as in unconsolidated highly permeable formations. If loss of circulation is not cured, then generally a remedial job is required. Many lost circulation problems can be cured by adding bridging material to the cement slurry. The bridging material is designed to bridge over fractures, blocking weak zones and increasing the resistance of the zone to pressure breakdown. Modified cements can also be used to cure lost circulation such as quick setting cements, thixotropic cements and lightweight cements. These tend to have more specialised applications and can be quite complex and expensive.

1.3.9

Salt Saturated Cement Salt sections can only be effectively cemented by salt saturated slurries. Fresh water cement would cause leaching of a salt zone at the interface and no cement bond would be possible. A good cement bond is only really possible across salt zones with a salt saturated slurry.

1.3.10 Radioactive Tracers It is occasionally important to monitor the cement displacement to accurately position the top of cement. For example, excess cement during the cementing of conductors on a template could block the rest of the template. A radioactive tracer can be added to the cement at the beginning of the job and the Schlumberger GR tool can monitor its displacement up the annulus. Fresh tracer should be ordered just before the job takes place as its radioactive half life is quite short. The tracers used in our cement operations are Tecnesium, Tc 99 or Iodine. Tc 99 has a half life of 6 hours at a dosage of up to 300 millicuries. 1.4

Planning The success of any cement job will be dependent upon the Drilling Representatives planning and checking in three major areas prior to commencement of any cement job, i.e. 1.

Inspection and testing of equipment.

2.

Calculations.

3.

Pre-planning of contingency operations.

These are covered in detail in the section on responsibilities (3010/GEN).

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1.5

Quality Control

1.5.1

Bulk Samples The rig is to safeguard itself from contamination by a wrong delivery of material from the supply vessel. Samples of cement are to be collected prior to and after topping up the silos. Liquid additives are to be checked prior to topping up the LAS storage tanks. Cement can be differentiated from barytes and bentonite in several ways: 1.

Take a sample of bulk material and rub it between the fingers under a stream of water. Bentonite can be detected by the gelling. Cement and barytes can be differentiated by the reaction with dilute hydrochloric acid. Cement starts to bubble upon addition of hydrochloric acid.

2.

Bulk materials have different specific densities. They can be differentiated by weighing fixed volumes, i.e. Bentonite Barytes Cement

2.5 - 2.6 g/cm3, 100 mls sample weighs 115 g 4.2 - 4.3 g/cm3, 100 mls sample weighs 260 g 3.1 - 3.2 g/cm3, 100 mls sample weighs 180 g

: : :

Liquid additives can also be identified by checking the density with hydrometers and also comparing the other physical properties, e.g. colour, with the product data sheet. 3.

Procedure for Determining Bentonite Content in a Cement Blend The following test procedure should be performed by the Mud Engineer on the rig. It is accurate to ± 1% and enables cement samples containing an unknown bentonite content to be investigated. Take 10g of cement sample, weight measured to two decimal points if possible. Dilute to 50 cm3 with water in the Erlenmeyer Flask. Add 10 cm3 5N sulphuric acid. Add methylene blue solution from a burette to the flask, this contains 3.74g USP grade per 1,000 cm3 water. After each addition of 5 cm3, shake the contents for about 30 seconds. While the solids are still suspended, remove one drop of liquid with the stirring rod and place the drop on filter paper. The end point of the titration is reached, when dye appears as a blue ring surrounding the dyed solids. When the blue tint spreading from the spot is detected, shake the flask an additional 2 minutes and place another drop on the filter paper. If the blue ring is again evident, the end point has been reached. If the ring does not appear, add 1 cm3 more of the methylene blue and continue as before until a drop taken after shaking 2 minutes shows the blue tint. The amount of bentonite present can be determined as follows: No Bentonite 2.5% 5.0% 7.5% 10.0%

1.5.2

-

Blue tint appears after first addition of 5 cm3 methylene blue. 10 ml required for blue tint. 20 ml required for blue tint. 30 ml required for blue tint. 40 ml required for blue tint.

Potential Problems of Mixing Different Shipments of Cement Blends Cement will age in a silo, especially if stored in small quantities. Its reactivity will change, resulting in a different pumping time to subsequent load-outs, even though it may have originated from the same mill run. This problem worsens with depth, i.e. the reactivity of Class G + 35 changes more than Class G + 8 or neat Class G cements.

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In addition to a change in reactivity, when second load-outs are used to top-up silos, it becomes necessary to sample and test both the old and new batches of cement. This can lead to confusion and it has been known for a thickening time of 4.5 - 5 hours obtained with one lot of samples to change to 2.5 hours with new samples. To avoid these problems the practice of topping up silos with second load-outs should only be undertaken after consulting Drilling Fluids Group in Dyce. The correct course of action is to dump the old batch of cement, clean out the silo and ship one blend sufficient for twice the job (plus abandonment/suspension plugs in the case of Class G + 35). 1.5.3

Sampling and Packaging The cement company will test the rig samples to tailor the cement slurry and provide an accurate thickening time. The cement company will supply a box with suitable containers for the collection of samples. The quantities required are: Cement Water Liquid Additive

: : :

10 kg from each silo 1 gal 500 mls of each additive

The samples are to be sent in by the Cementing Service Company Engineer with the following details included on the sample box: Rig Name Well Number Type of Cement Job (e.g. 13 3/8" casing) and Setting Depth Type of Cement and Silo Number Type of Additive Sampling and Packaging Instructions for Cement and Additives Sampling Cement from Surge Tank: Purge lines from bulk to surge tank. Ensure lines clear and surge tank completely empty. Fluff cement and transfer 2 tonnes approx. to surge. Open discharge on surge and allow some cement to fall out prior to filling the sample tin. Sampling Cement from Bulk Silo: Fluff cement in silo for approximately 60 mins. Depressurise silo. Open hatch. Take sample. Try to dig sample from below the top few inches since this part has been exposed to more air than the bulk. Packaging Cement: It is most important that the sample obtained above remains representative of the bulk cement from which it was sampled otherwise the exercise will have been a waste of time. The cement must be kept dry and be subjected to minimum exposure to the atmosphere while in transit to the laboratory. This can be achieved if the cement is packaged as follows: -

Packed in an undamaged tin. Minimum 5 kg, preferably 10 kg. Tin lined with two unused polythene bags. Tin filled to maximum, maximum air excluded. Polythene bags individually tied with tape or string. Tin labelled : Cement type/batch no., when and where sampled.

BP EXPLORATION


Section

:

3050/GEN

Rev.

:

2 (3/91)

Page

:

8 of 12


Sampling/Packaging Additives: Where possible, dry additives should be sampled from a sack of the same batch number to be used on the actual cement job. The sample should be placed in a clean, dry plastic bottle with a lid. 0.5 litres is usually sufficient. Label the bottle. The lid should be wrapped with PVC tape to prevent any leakage during transit. Liquid additives should be sampled from the same batch of additive to be used on the actual cement job. It is important to agitate liquid additives prior to sampling since they are usually suspensions and settling of solids will occur, especially with retarders, which will lead to an uneven distribution of retarder in the tank or drum. When sampled from an LAS system, make sure the tank is circulated for 30 minutes using the discharge pump prior to obtaining the sample. When sampling from a drum, roll the drum for 5 - 10 minutes prior to taking sample. Container for Above Samples: In order to keep the above samples free from damage, they must be packed in a strong wooden or metal box. Ex-ammo boxes make satisfactory containers. Additional samples are to be collected during the cement job for further analysis in case of problems. Samples are to be collected of the cement, the base water (i.e. drillwater or seawater), the individual liquid additives and the actual mixwater after addition of the additives. These samples are to be sent into town in the event of any problems or when additionally requested. All samples will be clearly labelled to identify the contents and where the sample was collected, e.g. cement from Silo No. 2 or surge tank, water from drill water tank No. 2 or mixwater from 2nd tank. Regular samples of the cement slurry should be collected in polysstyrene cups. These can be placed in a heated oven as a check on the cement setting, however, this is not an accurate check as water is evaporated from the slurry in the oven. It must be recognised for deep, high temperature wells this type of surface test can be totally erroneous since pressure downhole influences thickening reactions as well as the "drying-out" in the oven.

SUBJECT:

CEMENT ADDITIVES

0.05 - 0.40

R-14L

Sugar Derivative

Fresh/Sea/Salt Sat

200 - 350

1.31

0.05 - 0.30

Too sensitive below 200 deg F.

Dowell

D-81

Lignosulphonate

Fresh/Sea/Salt Sat

Up to 180

1.25

0.01 - 0.25

As R-12L.

D-801

Lignosulphonate

Fresh/Sea/Salt Sat

150 - 250

1.20

0.1 - 0.5

D-109

Organic Acid

Fresh/Seawater

180 - 300

1.26

0.01 - 0.25

As R-14L.

D-110

Organic Acid

Fresh/Seawater

180 - 300

1.13

0.01 - 0.50

Diluted version of D109 to optimise concentration.

D-28

Organic Acid plus

Fresh/Sea/Salt Sat

200 - 400

1.25

0.01 - 0.2% BWOC

Extremely sensitive. Careful testing required.

Halliburton

HR-6L

Lignosulphonate

Fresh/Sea/Salt Sat

Up to 200 (200 220 depending upon slurry).

1.21

0.03 - 0.5

Effective above 200 deg F but at high concentration.

HR-12L

Lignosulphonate

Fresh/Sea/Salt Sat

200 - 300

1.19

0.03 - 0.5

As R-14L.

Component R

Inorganic Salt

Fresh/Sea/Salt Sat

Up to 600 Deg F

-

-

This is an intensifier added to extend the temperature range.

TABLE 1

3050/GEN

1.29

:

200 - 300

Section

Fresh/Sea/Salt Sat

BP EXPLORATION

Lignosulphonate

2 (3/91)

R-15L

Possibility of temperature gellation over 200 deg F. Results are unpredictable at high temperature.

:

0.02 - 0.55

R-12L

Rev.

1.19

BJ

9 of 12

Up to 230

Retarder

Comments

:

Fresh/Sea/Salt Sat

Chemical Type

Page

Lignosulphonate

Additive

DRILLING MANUAL

Additive SG

Approximate Concentration Range Gal/SX

Cement Company


Mix Water Type

Temperature Range Deg F

Additive Class

SUBJECT:

CEMENT ADDITIVES

Fresh/Sea/Salt Sat

D-45L

Poly Amine

Not used in the North Sea.

D-5

Latex

Fresh/Sea/Salt Sat

Up to 200

1.10

0.9

Not used in the North Sea.

Dowell

D-73

Cellulose

Fresh/Seawater

To 400

1.05

0.2 - 0.5

Must be used in conjunction with D80 (is to be phased out).

D-603

-

Fresh/Seawater

80 - 240

1.09

0.1 - 0.35

Current standard additive. It is to be modified to cover higher temperature.

D-112

Cellulose

Fresh/Seawater

80 - 260

1.15

0.5 - 3.0% BWOC

Used in light-weight slurries in conjunction with a dispersant.

D-59

Cellulose

10% - 37% Salt

Up to 250

1.34

0.2 - 1.0% BWOC

Secondary reaction is retardation.

Halliburton

Halad-10L

Cellulose

Fresh

Up to 210

1.08

Up to 0.8

Large concentration required in salt water. Slightly retards at low temperature.

Halad-322L

Cellulose

All Waters

Up to 230

1.07

Up to 1.0

Does not retard at low temperatures.

Halad-22A

Cellulose

Fresh/Seawater

Up to 350

Solid Grade

Halad-14

Cellulose

Fresh

Up to 400

Solid Grade

Accelerator

BJ Dowell Halliburton

A-7L D-77 Liquid CaCl2

Cal. Chloride Cal. Chloride Cal. Chloride

Any Any Any

Up to 100 Up to 100 Up to 100

1.35 1.31 - 1.37 1.26

TABLE 2

High temperature additive.

0.1 - 0.8 0.1 - 0.8 0.1 - 0.8

3050/GEN

-

:

1.06

Section

Up to 350

2 (3/91)

Fresh/Sea/Salt Sat

:

Standard fluid loss additive.

Rev.

0.3 - 0.5

D-19L

10 of 12

1.04

BJ

:

Up to 300 Deg F

Fluid Loss

BP EXPLORATION

Poly Amine

Chemical Type

Page

Comments

Additive

DRILLING MANUAL

Additive SG


Cement Company


Mix Water Type


Additive Class

SUBJECT:

CEMENT ADDITIVES

0.5 gal/10 bbl slurry

Dowell

D-47

-

Fresh/Sea/Salt Sat

Up to 400 Deg F

0.99

Up to 0.05

Halliburton

NF-1

Phosphate

Fresh/Sea/Salt Sat

No Limitations

0.96

2-10 pts/10 bbl slurry

D-air-2

-

Fresh/Sea/Salt Sat

No Limitations

1.00

2-10 pts/10 bbl slurry

BJ

D-31L

Sulphonate

Fresh/Seawater

No Limitations

1.23

0.02 - 0.2

Used with cements which are difficult to disperse (e.g. (Blue Circle).

Dowell

D-80

Sulphonate

Fresh/Seawater

No Limitations

1.21

0.02 - 0.2

Used with cements which are difficult to disperse (e.g. (Blue Circle).

D604

-

Fresh/Seawater

No Limitations

1.21

0.05 - 0.2

D-45

Organic Acid

Salt Saturated

No Limitations

1.50

0.05 - 0.2% BWOC

Halliburton

CRR-2L

Sulphonate

Fresh/Seawater

No Limitations

1.18

Up to 0.44

Extender


A-3L D-75 Liquid Econolite

Sodium Silicate Sodium Silicate Sodium Silicate

Seawater Seawater Seawater

No Limitations No Limitations No Limitations

1.50 1.40 1.36

0.1 - 0.6 0.1 - 0.6 0.1 - 0.6

Weighting Agent


W5 D76 Hidense

Heamatite Heamatite Heamatite

Any Any Any


4.95 4.95 4.95

As required. As required. As required.


WI D31 -

Barytes Barytes Barytes

Any Any Any


4.20 4.20 4.20

As required As required As required

Dispersant

TABLE 3

Silicate slurries are prone to excessive gel strength development, particularly below 12.0 ppg.

3050/GEN

-

:

No Limitations

Section

Fresh/Sea/Salt Sat

BP EXPLORATION

-

2 (3/91)

D-6L

:

0.5 gal/10 bbl slurry

D-21L

Rev.

0.88

BJ

11 of 12

No Limitations

Defoamer

Comments

:

Fresh/Sea/Salt Sat

Chemical Type

Page

Phosphate

Additive

DRILLING MANUAL

Additive SG


Cement Company


Mix Water Type


Additive Class

SUBJECT:

Silica Flour (200 #)

Any

Above 230

2.63

35% BWOC

D-8c

Silica Sand (80 - 140 #)

Any

Above 230

2.63

35% BWOC

D-66

Silica Flour (200 #)

Any

Above 230

2.63

35% BWOC

D-30

Silica Sand (70 - 200 #)

Any

Above 230

2.63

35% BWOC

Silica Flour

Silica Flour

Any

Above 230

2.63

35% BWOC

Silica Sand

Silica Sand

Any

Above 230

2.63

35% BWOC

Additive

Chemical Type

Retrogressive Strength

BJ

D-8

Dowell

Halliburton

Comments

BP EXPLORATION

Additive SG


Cement Company

DRILLING MANUAL

Mix Water Type


Additive Class


CEMENT ADDITIVES

TABLE 4

Page

Rev.

Section

:

:

:

12 of 12

2 (3/91)

3050/GEN

BP EXPLORATION


Section

:

3100/FIX

Rev.

:

1 (7/91)

Page

:

1 of 5

30" CEMENTATION - FIXED INSTALLATIONS : RUN/DRILL/RUN/CEMENT

30” CONDUCTOR On fixed installations where it is not feasible to run a float shoe, as the conductor is first used as a guide string, the following procedures must be used.

1.1

After the 17 1/2” pilot hole has been underreamed to 36”, as per Sections 1110/PLA and 1280/GEN, run 30” conductor to setting depth. Hang off the conductor in sub-base as per running procedures. Run and space out cement stinger to be +/- 90 ft above the 30” shoe. Note: Bottom 60 ft of stinger to be GRP pipe.

Note: Ensure 30” x 5” annulus open to atmosphere. 1.2

Pump conductor volume of seawater down 30” x 5” annulus, this cleans inside of conductor of gumbo and provides a free passage for the temperature tool.

1.3

Mix and pump required volume of lead cement. Excess of 200% on open hole to be used.

Note: A 1,000 sx tail slurry will be used. 1.4

Monitor 30” x 5” annulus for seawater returns. If seawater returns are observed, close the annulus and pump sufficient seawater down the annulus to displace cement to bottom of stinger. Keep the annulus closed and monitor pressures.

1.5

Mix and pump remaining volume of lead and 1,000 sx of both as accelerated tail.

1.6

Displace cement with seawater to clear the stinger.

1.7

Run temperature profile tool to locate TOC inside the 30” conductor.

1.8

Pump additional seawater down the annulus to leave TOC inside the 30” conductor 40 ft above the shoe - monitor annulus pressures.

1.9

Re-run temperature profile tool to confirm TOC inside the 30” conductor is below the stinger. Also locate TOC outside the conductor.

1.10

Pull out temperature tool and close all valves on the running tool.

1.11

Wait on cement with stinger in place and maintain the final differential pressure.

Note: If conductors are being batch set and drilling out is not to follow: i)

Once cement has set, circulate the 30” conductor to inhibited seawater and pull the drill pipe stinger. Seawater to be inhibited with: Tros C-714 Tros TK-457

500 ppm 200 ppm

Note: These chemicals are incompatible and should not be mixed together in undiluted form. The C-714 should be added to the seawater first followed by the TK-457. ii)

Once the stinger is pulled the top 10” of conductor should be top filled, to give a further corrosion barrier, with Nalfleet MDP-1 and a trash cover installed on the conductor.

BP EXPLORATION


Section

:

3100/FIX

Rev.

:

1 (7/91)

Page

:

2 of 5


2.

IF NO SEAWATER RETURNS are seen after required volume of lead cement has been pumped, proceed as follows. See page 4 of 5 for diagram.

2.1

Mix and pump 1000 sx of accelerated tail cement.

2.2

Monitor 30” x 5” annulus for seawater returns and if returns are observed displace as per Section 1.4.

2.3

Mix and pump the remaining accelerated tail cement (i.e. a total of 1000 sx tail cement will be pumped).

2.4

Proceed with programme from Section 1.6 onwards.

3.

IF NO SEAWATER RETURNS are seen in Secton 2.2 while pumping tail cement, pump required volume of lead cement followed by 1000 sx of tail cement then proceed as follows. See page 5 of 5 for diagram.

3.1

Displace cement with seawater to clear the stinger.

3.2

Monitor 30” x 5” annulus for seawater returns. If no seawater returns at surface, run electric wireline conductivity tool to establish seawater level in the 30” x 5” annulus.

3.3

Close the annulus and pump sufficient seawater down the annulus to put TOC inside the 30” conductor at the bottom of the stinger.

3.4

Proceed with the programme for Section 1.7.

Section : 3100/FIX

DISPLACE CEMENT IN ANNULUS TO BOTTOM OF STINGER, THEN CLOSE IN

1 (7/91)

PUMP LEAD SLURRY UNTIL SEA WATER AT SURFACE

:

910079 / 1

CEMENT STINGER RUN, BOTTOM 60' G.R.P. PIPE

Rev.

30" RUN TO SETTING DEPTH

3 of 5

30" SHOE

BP EXPLORATION

SEA BED

:

PUMP SEA WATER DOWN ANNULUS & W.O.C.

M.S.L.

Page

PUMP TAIL SLURRY & DISPLACE CEMENT FROM STINGER

RUNNING TOOL

DRILLING MANUAL

TEMPERATURE PROFILE TOOL



SUBJECT:

ROTARY TABLE

Section : 3100/FIX


1 (7/91)

910079 / 2

PUMP LEAD CEMENT FOLLOWED BY ACCELERATED TAIL, UNTIL SEA WATER RETURNS AT SURFACE

:


Rev.


4 of 5

30" SHOE

BP EXPLORATION

SEA BED

:


M.S.L.

Page

PUMP REMAINING TAIL SLURRY & DISPLACE CEMENT FROM STINGER

RUNNING TOOL

DRILLING MANUAL




SUBJECT:

ROTARY TABLE

: 3100/FIX

910079 / 3

Section

PUMP LEAD CEMENT FOLLOWED BY 1000 SX ACCELERATED TAIL

BP EXPLORATION


1 (7/91)


:

30" SHOE

Rev.


SEA BED

5 of 5


M.S.L.

:

DISPLACE CEMENT FROM STINGER & LOCATE SEA WATER LEVEL

RUNNING TOOL

Page


DRILLING MANUAL



CONDUCTIVITY TOOL

SUBJECT:

ROTARY TABLE

BP EXPLORATION


Section

:

3100/JAK

Rev.

:

1 (11/89)

Page

:

1 of 2

30" CEMENTATION USING STAB-IN TECHNIQUE

1.

30” CONDUCTOR

1.1

The 30” may be cemented with a stab-in shoe.

1.2

HWDP may be required as the cementing stinger to ensure stab-in assembly cannot be pumped out of the float shoe if no latch assembly is used. A centraliser will be run above the stab-in stinger, on the bottom joint of HWDP/DP.

1.3

Prior to stabbing into the shoe, rig up and circulate to confirm circulation through the drill pipe. Stab-in to the shoe and fill 5” x 30” annulus with seawater. Note volume required and ensure level is constant. Circulate a minimum volume equal to the 30” x 36” annulus volume. Observe level inside 30” remains constant confirming cement stinger seal is maintained.

1.4

The use of an iodine tracer and GR tool to monitor top of cement can be considered when applicable. On jack-up rigs an ROV/divers should be used to monitor cement returns at seabed. If a tracer is to be used, rig up logging equipment and prepare to run the GR logging tool to ± 3m from the DP centraliser inside the 30”. The GR tool is to be run just after the tracer has been mixed to avoid saturating the tool.

1.5

Pump preflush and cement slurry volumes. Actual details will be specified in the drilling programme. -

The preflush will normally be seawater, any alternative will be specified in the drilling programme.

-

Lead cement to be Class ‘G’ mixed in seawater to 16.0 ppg, 1.92 SG. Tail cement to be 300 sxs class ‘G’ mixed with seawater containing 2% by weight calcium chloride or equivalent. Slurry weight to be 16.0 ppg, 1.92 SG. Alternatively, the entire job will be carried out with the tail slurry. Slurry volume to be: a)

If a tracer is used: Minimum - gauge hole volume. Maximum - 200% excess on gauge hole volume. An initial 10 bbls of slurry will be mixed and pumped. Add iodine tracer and then continue mixing the lead slurry.

b)

If no tracer, use 200% excess on the gauge hole volume.

Whilst mixing cement continuously monitor level in 5” DP x 30” conductor annulus. 1.6

1.7

Complete mixing slurry and displacement as follows: a)

If a tracer is used, when the GR tool has indicated the trace downhole, pull back the tool in +/15m stages and note the cement rise, compare with calculated rate. When trace is at required level start mixing and pumping tail slurry followed by the displacement.

b)

If no tracer, mix and pump calculated volumes of lead and tail followed by the displacement.

Displace the cement with seawater to the 30” conductor shoe. Check for backflow at the cement unit. If backflow occurs: -

Redisplace the volume of backflow and a further overdisplacement of one barrel.

-

Hold pressure until surface samples are set.

BP EXPLORATION


Section

:

3100/JAK

Rev.

:

1 (11/89)

Page

:

2 of 2

30: CEMENTATION USING STAB-IN TECHNIQUE

Bleed off pressure and un-sting from shoe and POH.

If no backflow, un-sting from shoe while observing 5” DP x 30” annulus level for negative flow. If negative flow occurs: -

Restab stinger immediately and wait until surface samples are set.

-

Un-sting from shoe and POH.

1.9

If no negative flow, pull back 5m and circulate conventionally to remove any excess cement.

1.10

If run, pull GR tool and rig down wireline.

1.11

POH cement stinger assembly. Refer to Section 1160/JAK.

1.12

Ensure all cement bulk, cement unit equipment and lines are thoroughly overhauled, blown out, and cleaned immediately upon completion of cementing operation.

1.13

30” cementing calculations to be performed are: 1.

Open hole volume and appropriate excess.

2.

Cementing stinger volume.

3.

Total slurry volume.

4.

Cement, additive and mixwater requirements for lead slurry (if used).

5.

Cement, additive and mixwater requirements for tail slurry.

6.

Final displacement volume, i.e. DP capacity.

7.

Hydrostatic pressure inside 30” shoe prior to stinger withdrawal.

8.

Hydrostatic pressure outside 30” shoe prior to stinger withdrawal.

9.

Collapse pressure at 30” shoe prior to pulling stinger out of shoe.

10. Minimum cement height to balance seawater column inside 30” conductor after final displacement. 11. Weight of 30” when landed. 12. Volume of seawater to fill 5” x 30” annulus from sea level to surface. 13. Depth of trace when lead slurry is changed to tail slurry (if tracer to be used). 14. Slurry mixing time. 15. Total job time compared to thickening time.

BP EXPLORATION


Section

:

3100/SEM

Rev.

:

1 (1/94)

Page

:

1 of 5

30" CONDUCTOR AND TOP-UP CEMENTATIONS

1.

30" CONDUCTOR CEMENTATION

1.1

Perform the general pre-cementing checks as detailed in Sections 3020/GEN, 3030/GEN and 3040/GEN.

1.2

The following pre-job calculations are required: 1. 2. 3. 4. 5. 6. 7.

Slurry volume. Lead/tail mixwater/additive volumes. Preflush volumes/displacement volume. Differential pressure at end of displacement. Buoyed conductor weight after running casing. Buoyed conductor weight after displacement. Landing string buoyed weight.

1.3

In addition to the above, ensure that the top-up tubing stinger can pass through the PGB in case a topup cementation is required.

1.4

The 30” is normally run with a guide shoe only (i.e. no float valves). Two joints of 5 1/2” GRP tubing are used in place of DP, as a stinger below the 30” housing hydraulic running tool to help ensure a good conductor cement job. (The fibre-glass casing will be straight forward to drill out should it get cemented in.) Make up two joints of GRP casing on the catwalk with chain tongs together with a crossover and drillpipe pup joint. (The pup joint makes handling easier.) Run drillpipe using 2 sets of elevators to space the bottom of the stinger 15m above the shoe. The landing plate will take the weight of the stinger, hanging from the DP elevators.

1.5

Make up the housing hydraulic running tool to the stinger and then to the 30” housing.

1.6

With the conductor at setting depth, circulate the casing contents with seawater. Do not exceed a circulating rate of 250 gpm.

1.7

Rig up and pressure test the cement lines.

1.8

Mix and pump spacer and cement as per recipe. The required TOC is seabed. If it is not possible to clearly identify cement returns, or if no returns are noted, 200% excess slurry (on the open hole volume) should be pumped. The standard cement slurry is: Lead:

Class G cement 1.92 SG 5.13 gal/sk seawater Yield 1.17 cu.ft/sk.

Tail:

500 sks Class G cement 4.88 gal/sk seawater 2% BWOC CaCl2 Yield 1.19 cu.ft/sk 1.93 SG

To eliminate cement fall-back once the cement is in place, and to promote early strength development, an alternative single slurry may be considered: Class G cement 4.88 gal/sk seawater 2% BWOC CaCl2

BP EXPLORATION


Section

:

3100/SEM

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:

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Yield 1.19 cu.ft/sk 1.93 SG

Note: Fluorescent dye is to be added to the first 20 bbl of mixwater to aid identification. 1.9

Displace the cement with seawater at 5 BPM, or as necessary, to 6m above the casing shoe. The annular velocity should not exceed that of the final circulation. In cases where there is a risk of the casing floating, the cement must be displaced with mud. Use the cement pump for displacement. Observe for cement returns at seabed with the SSTV or ROV. Note the differential pressure at the end of displacement.

1.10

When displacement is complete, hold back pressure on the drillpipe and WOC. Hold tension on the running string to ensure that the angle is kept at less than 1 degree until the surface samples have set. Allow a minimum of 6 hours. When the surface samples are hard, slack off the casing string weight. When slacking off the weight, observe the wellhead closely for movement.

Note: If movement is observed, pick up and continue to hold tension on the wellhead until the cement completely sets. 1.11

Record the angle of PGB from the slope indicator. Release the housing hydraulic running tool. Pull back the stinger length and circulate seawater to wash the 30” suspension joint. Strap out and record the datum depth.

2.

30” TOP-UP CEMENTATION

2.1

To determine whether a top-up cementation is required, refer to Figure 1. If it is visually clear that full returns occurred and that there is still cement at seabed, after releasing the running tool, then it will not be necessary to tag the cement.

2.2

If there is any doubt about the height of cement in the annulus, run the following stinger and tag the cement in the 36”/30” annulus on either side: -

Diverter sub. 3 joint x 3 1/2” tubing. 2 7/8” or 2 3/8” EUE pin x 4 1/2” IF box X/O. 5” dp.

To ease detection of hard cement, mark the stinger in metre bands at the rotary table as the pipe enters the PGB funnel. Check the cement level on diametrically opposed sides of the annulus.

Note: Run the stinger into the annulus as far as possible, without putting any 5” drillpipe into the annulus. A top-up cementation should be carried out automatically if: Case 1

-

(water depths up to 250m, regardless of whether 20” casing is run). Cement is tagged more than 9m below seabed on either side.

Case 2

-

(water depths greater than 250m, but only if the 20” casing is to be used and the wellhead is pre-loaded into the 30” housing as is the case with the Universal wellhead). Cement is tagged more than 3m below seabed on either side.

BP EXPLORATION


Section

:

3100/SEM

Rev.

:

1 (1/94)

Page

:

3 of 5


2.3

Other factors should be considered at this stage that may lead to a top-up job being performed even if the limits indicated above are not exceeded, e.g. localised seabed currents, or PGB bullseye indicator moving.

2.4

Guidelines for minimum top-up volumes are as follows:

Penetration

Volume

0 - 10m 10 - 20m 20 - 30m

1,000 cu.ft 1,500 cu.ft 2,000 cu.ft

Note: a)

When running the stinger ensure that the stinger connections are strap welded.

b)

For exploration wells that are in less than 250m of water, on completion of the top-up job, place the stinger 3m below seabed and circulate 10 bbls of seawater to flush/wash cement down to where the 30” will be cut on abandonment. Repeat this operation with the stinger on the other side of the wellhead.

c)

To avoid waiting on cement, the annulus level will be checked after running 20” casing, prior to running the BOP.

2.5

Nipple up and pressure test the cement lines.

2.6

Prior to performing the cementation, consideration should be given to spotting a highly viscous LCM plug on top of the existing cement. The stinger should then be withdrawn 1 - 2m before the cement is displaced.

2.7

Mix and pump cement slurry as per the recipe. During cementing the stinger should be slowly withdrawn from the cement in order to attempt to string out the slurry column.

2.8

Displace the 5” drillpipe with seawater.

Note: If possible, observe returns at seabed with the ROV. 2.9

Pull the 2 3/8”/2 7/8” tubing out of the annulus and circulate to remove any cement left in the string. POOH.

2.10

Ensure that the following reports have been completed. Copies are to be retained in the offshore well file.

2.11

a)

Conductor Log Tally Sheets.

b)

Conductor Cementation Report.

c)

Pressure recording charts, signed by cementer and BP Drilling Supervisor.

d)

36” Hole Drilling Evaluation.

e)

Casing and Cementing Evaluation.

f)

PGB drawings.

Prepare a drawing of the 30” housing showing the distance from the top of the housing to the seabed.

Note: This drawing is to be updated after every casing job.

BP EXPLORATION


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30" TOP-UP CEMENTATION USING TITUS EQUIPMENT If a DrilQuip wellhead system is in use, it may include the TITUS automatic top-up system (see Section 2100/SEM for details). In this case, the following procedure should be followed:

3.1

Perform 30" primary cement job as per normal. Displace cement. Check for backflow.

3.2

Drop 2 1/2" steel ball. Open shear sleeve with circa 500 psi.

3.3

Establish circulation through distribution ring. Circulate at low rate to keep ports open and wash away any cement from the primary cement job. Continue circulating until approximately 1 hour before anticipated release time of the 30" running tool.

3.4

Perform top-up cement job using quantities advised in 30" conductor cementing programme. Displace cement using calculated string volume to cementing swivel, plus 4 bbls excess. Hold pressure until no backflow is observed.

3.5

Move grouting hose stab handle to unlatch position with ROV; unstab with ROV.

3.6

Release 30" running tool. Pick up string and confirm grouting hose stab is free.

3.7

Thoroughly wash out the cement swivel on recovery.

BP EXPLORATION


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3100/SEM

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30" CONDUCTOR AND TOP-UP CEMENTATIONS FIGURE 1 30" CONDUCTOR TOP UP CEMENT JOB FLOW CHART TOP 2 JOINTS OF 30" COND. SHOULD BE 1. 1/2 " WT X52 WITH A HEAVY DUTY CONNECTOR NOTE (I)

CARRY OUT 30" CEMENTATION TO SEABED NOTE (II)

GOOD VISUAL CONFIRMATION OF CEMENT TO SEABED AND NO CEMENT SLUMP ? NOTE (III)

YES

30" CEMENT ATION COMPLETE CONTINUE WITH DRILLING PROG.

NO NO

TAG CEMENT IN 36" / 30" ANNULUS

CEMENT TAGGED BELOW: CASE 1 or CASE 2 9m ON 3m ON EITHER EITHER SIDE SIDE ? (IV)

NO

OTHER FACTORS TO CONSIDER ? NOTE (V)

YES

YES PERFORM TOP UP CEMENT JOB ON EITHER SIDE OF 36" / 30" ANNULUS NOTE (vi)

NO

GOOD VISUAL CONFIRMATION OF CEMENT TO SEABED AND NO CEMENT SLUMP ? NOTE (III)

YES IS IT AN EXPLORATION WELL IN LESS THAN 250m WATER ?

NO

YES PLACE STINGER 3m BELOW SEABED AND PUMP 100BBLS SEAWATER REPEAT ON OPPOSITE SIDE - NOTE (VII)

2179 / 80

BP EXPLORATION


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20"/18 5/8" CEMENTATION USING STAB-IN TECHNIQUE

20”/18 5/8” CASING CEMENTATION

Note: This technique should only be used when there is no possibility of casing collapse due to the hydrostatic differential of a cement column. If there is any doubt then a pack off technique must be used. 1.1

The 20”/18 5/8” will normally be cemented with stab in float collar and float shoe 1 joint apart.

1.2

The cementing stinger will consist of HWDP and DP to ensure stab in assembly cannot be pumped out of the float collar if no latch assembly is used. A centraliser will be run above the stab in stinger, across a DP protector on the bottom joint.

Note: If a latch down dart is used, check internal upsets on DP will allow passage of the dart. 1.3

If cement volumes are to be based on BGT log, use extension arms.

1.4

With the 20”/18 5/8” casing run to the desired depth, ensure that the casing space-out is such that a convenient working height is achieved for running the cement stinger.

Note: If possible, the casing may be spaced out and backed off +/- 0.8m below the rotary table to allow slips to be used to run the DP stinger. Alternatively, the drillpipe stinger will need to be run using a double elevator arrangement on top of the 20”/18 5/8” casing. 1.5

Run stinger on 5” drill pipe and stab in. Fill up 5 x 20”/18 5/8” annulus. Observe level. Ensure that the seals on the stab-in sub are not leaking.

1.6

Establish circulation + circ 120% annulus contents.

1.7

Preflush with 180 bbls inhibited seawater.

1.8

Mix and pump lead cement, add radio active trace, if required, after 10 bbls have been pumped. Run Schlumberger GR tool in 20”/18 5/8” x 5” annulus once radio active trace has been pumped, to avoid saturating the GR tool.

1.9

Monitor cement trace with GR - once trace observed pull GR back in 50 ft stages and wait for trace.

1.10

Once trace seen at required height change to tail slurry.

1.11

Mix and pump the greater of 500 sks or 100 linear metres of tail slurry.

1.12

Displace cement with seawater until top of cement is 60m above the float collar, in the drill pipe. This is sufficient to leave ca. 3m of cement on top of the float collar once the stinger is pulled.

1.13

Pull stinger and allow cement to fall.

1.14

Locate top of cement with GR.

1.15

Pull out with Schlumberger.

1.16

Pull out drill pipe.

Note: a) If trace is lost pump total volume of cement based on BGT caliper. b) If no BGT is available, then use 100% excess on gauge hole. c) If trace rises ahead of calculated rate from BGT volume, channelling may have occurred. Degree of channelling will dictate when tail has to be mixed.

BP EXPLORATION


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20"/18 5/8" CEMENTATION USING STAB-IN TECHNIQUE

1.17

Check for backflow, pull stinger back 10m and allow cement to fall.

1.18

Locate TOC with GR and POH GR tool.

1.19

Circulate casing to SW at maximum pump rate - flow check.

1.20

POH stinger.

1.21

Back out and lay down the 20”/18 5/8” landing string.

1.22

Flow check prior to rigging down riser and diverter.

1.23

Ensure all cement bulk, cement unit equipment and lines are thoroughly overhauled, blown out, and cleaned immediately upon completion of cementing operation.

1.24

Cementing calculations to be performed are: 1.

Slurry volume, caliper + shoe track volume.

2.

Lead and tail slurry volumes.

3.

Cement, additive and mixwater requirements for lead slurry.

4.

Cement, additives and mixwater requirements for tail slurry.

5.

Displacement volume.

6.

Differential pressure prior to pulling stinger.

7.

Collapse pressure at 20”/18 5/8” float shoe.

8.

Minimum cement height in annulus to balance fluid inside 20”/18 5/8” casing.

9.

Volume of seawater to fill 20”/18 5/8” x 5” annulus.

10.

Weight of cementing stinger and differential pressure limit to prevent pump out.

11.

Weight of 20”/18 5/8” prior to cementing.

12.

Preflush volume.

13.

Landing string weight in air.

14.

Rise rate of trace at various pump rates.

15.

Mud weight for displacement if 20”/18 5/8” is buoyant in the cement.

16.

Mud returns.

17.

Slurry mixing time.

18.

Total job time compared to thickening time.

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20"/18 5/8" CEMENTATION

1.1

Perform the general pre-cementing checks as detailed in Sections 3020/GEN, 3030/GEN and 3040/GEN.

1.2

The following pre-job calculations are required: 1.

Lead/tail slurry volumes.

2.

Lead/tail cement/mixwater/additive volumes.

3.


4.

Hydrostatic pressure for various cement positions during the job. Ensure that sufficient overbalance is present at all times.

5.

Calculate and prepare a graph of pumping pressures versus slurry and displacement volumes.

6.

ECD during cement job. Ensure that the ECD does not exceed that achieved during drilling the 26” hole.

7.

Differential pressure at end of displacement with TOC at seabed.

8.

Collapse pressure at 20” shoe.

9.

Casing load at wellhead after cementing.

10.

Landing string buoyed weight.

Note: a)

Slurry and displacement volumes to be calculated by the BP Drilling Supervisor, BP Drilling Engineer and the cementer.

b)

For slurry volume calculations, allow 100% excess on the open hole annular volume. The required TOC is seabed.

1.3

The 20”/18 5/8” casing will be cemented using conventional float shoe and float collar one joint apart and an SSR mandrel loaded with a top plug only.

1.4

When running the Dril-Quip SS15 Universal wellhead system ensure that the drill pipe dart on the rig will pass through the ring gauge supplied with the Dril-Quip hydraulic running tool (refer to Section 2200/SEM).

1.5

With the 18 3/4” housing landed in the 30” wellhead, establish circulation and circulate casing contents.

1.6

Make up the cement/plug launching head, cement head/cement kelly and lines. Pressure test to 3000 psi.

1.7

Pump spacer as per recipe.

1.8

Mix and pump the cement slurry as per the recipe. The standard recipe is: Lead:

Class G + 8% Bentonite in seawater 1.58 SG Yield 1.97 cu.ft/sk 10.88 gal/sk seawater Thickening time +/- 6-8 hours

BP EXPLORATION

DRILLING MANUAL SUBJECT: Tail:

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20"/18 5/8" CEMENTATION 100m annular height Neat Class G in seawater 1.92 SG Yield 1.15 cu.ft/sk 5.07 gal/sk seawater Thickening time +/- 5 hours

Note: Ensure that samples of cement slurry are taken regularly during mixing and set aside for observation. 1.9

Release the top plug launching dart and displace to the wiper plug with seawater using the cement unit. Shear the wiper plug (+/- 1800 psi) and continue displacing with seawater using the rig pumps.

1.10

Bump the top plug, noting the differential pressure at the end of displacement.

Note:

1.11

a)

If the plug does not bump after the calculated displacement, do not displace more than half the shoe track volume.

b)

Use the ROV or SSTV to verify returns to the seabed. Keep the unit on the seabed to observe the rigid lock-down of the wellhead.

Bleed off the pressure and check for backflow.

Note: If the floats do not hold and backflow occurs, re-displace the backflow volume and re-apply surface pressure. Hold the pressure until surface samples set. 1.12

After confirming that the float is holding, activate the rigid lock-down mechanism (refer to Section 2200/SEM).

Note: If the hot line method fails to activate the hydraulic lockdown, drop the Dril-Quip dart for the hydraulic lockdown and pressure up the running string to +/- 2000 psi to activate the rigid lockdown. Observe the outer sleeve indicator plate moving down with the ROV. Take a 5000 lbs overpull and rotate the running string 5 turns to the right. POOH. Observe the wellhead with the ROV for any cement deposits. If necessary RIH with the jet sub and wash away the excess cement. 1.13

If there is any doubt concerning the top of cement in the 36”/30” annulus, run the top-up cementing string as detailed in Section 3100/SEM to tag TOC. If required, perform a top-up job before running the BOP. POOH.

1.14

Ensure that the following reports have been completed. Copies are to be retained in the offshore well file. a) b) c) d)

1.15

20” Casing Log. 20” Cementation Report. 26” Hole Evaluation. 20” Casing and Cementing Evaluation.

Update the drawings of the wellhead/BOP stack-up.

BP EXPLORATION


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20"/18 5/8" CEMENTATION USING A CASING PACK-OFF

20”/18 5/8” CASING CEMENTATION

Note: If there is any risk of casing collapse due to hydrostatic differential of a cement column then a surface/wellhead pack-off must be used to maintain pressure inside the 20”/18 5/8” casing until the cement sets. 1.1

The 20”/18 5/8” will normally be cemented with a float collar and float shoe 1 joint apart.

1.2

The cementing stinger will consist of DP with a 30m fibre glass tail pipe, run to 10m above the float shoe.

1.3

If cement volumes are to be based on BGT log, use extension arms.

1.4

With the 20”/18 5/8” casing run to the desired depth and the casing pack-off installed, ensure that the casing space-out is such that a convenient working height is achieved for running the cement stinger.

Note: a)

Prior to installing the casing pack-off, ensure that the 20”/18 5/8” casing is full.

b)

If possible, the casing may be spaced out and backed off +/- 0.8m below the rotary table to allow slips to be used to run the DP stinger. Alternatively, the drillpipe stinger will need to be run using a double elevator arrangement on top of the 20”/18 5/8” casing.

1.5

Once DP stinger is run, check there are no leaks on the casing pack-off.

1.6

Establish circulation and circulate 120% annulus contents.

1.7

Preflush with 180 bbl inhibited seawater.

1.8

Mix and pump lead cement. Monitor for cement returns. Limit lead cement to 100% excess over theoretical volume.

1.9

Once cement returns are observed mix and pump the greater of 500 sks or 100 linear metres of tail slurry.

1.10

Displace cement with seawater to float collar. Observe differential pressure on drill pipe.

1.11

Hold back pressure until cement sets. Observe set on surface samples and compare to laboratory setting time.

1.12

Bleed off pressure slowly.

1.13

Pull out and break down cementing string.

1.14

Pick up string weight supported by slips. Remove slips. Ensure space out is not altered.

1.15

If cement returns were lost during the cement job and cement was not seen at surface a top up cementation will be required.

1.16

Back out landing joints.

1.17

Flow check prior to nippling down BOP/riser and divertor system.

1.18

Ensure all cement bulk, cement unit equipment and lines are thoroughly overhauled, blown out and cleaned immediately upon completion of cementing operation.

1.19

Cementing calculations to be performed are:

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20"/18 5/8" CEMENTATION USING A CASING PACK-OFF

1.

Slurry volume, i.e. caliper + shoe track volume.

2.

Lead and tail slurry volumes.

3.

Cement, additive and mix water requirements for lead slurry.

4.


5.


6.

Differential pressure.

7.

Collapse pressure at 20”/18 5/8” float shoe.

8.

Minimum cement height in annulus to balance fluid inside 20”/18 5/8” casing.

9.

Volume of seawater to fill 20”/18 5/8” x 5” annulus.

10.

Weight of cementing stinger.

11.

Weight of 20”/18 5/8” prior to cementing.

12.

Preflush volume.

13.

Landing string weight in air.

14.

Mud weight for displacement if 20”/18 5/8” is buoyant in the cement.

15.

Mud returns.

16.

Slurry mixing time.

17.


BP EXPLORATION


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9 5/8" CEMENTATION

1.

PREPARATION

1.1

Check the volumetric efficiency of the mud pumps immediately before the job and monitor both pit volumes and pump strokes during the displacement.

1.2

Ensure samples of bulk cement (from the silos to be used for the job), water and additives are sent to the Fluids Department in good time for Laboratory testing before the expected job date. Check preflush requirements and mixing procedures.

1.3

On platforms ensure that the kill line from the cement unit to the production facility is isolated before the unit is operated.

1.4

The 9 5/8” casing will normally be cemented with a float shoe and float collar two joints apart.

1.5

The 9 5/8” casing will normally be cemented in a single stage, bringing the lead cement slurry 100m inside the 13 3/8” shoe.

1.6

An ancillary pressure recorder is to be used to record the complete operation on a single chart. i.e.

Circulating the casing Pressure testing Preflush displacement Lead and tail slurry mixing Displacement Casing pressure test

This requires the recorder to be connected to one of the cement head or cement swivel outlets. 1.7

9 5/8” cementation calculations to be performed are: 1.

Weight of casing prior to landing, equipment safety factors, blockline etc.

2.

Weight of casing at hanger when cemented to ensure negative buoyancy when landing string held in elevators.

3.

Landing string buoyed weight when SSR in use.

4.

Circulation volume.

5.

Volume and density of preflush.

Note: On jack-up wells the spacer volume should be such that if the spacer is returned it indicates that the TOC is below the MLH. 6.

Reduction in hydrostatic due to preflush. Use height of preflush in gauge hole. Ensure that sufficient overbalance is present at all times.

7.

Lead and tail slurry volume including excess.

8.

Hydrostatic pressure when cement fully displaced. Check against expected frac pressure @ shoe.

9.

Cement, additive and mixwater requirements for lead slurry.

10.


11.

Minimum slurry volume, ignoring excesses.

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9 5/8" CEMENTATION

12.

Capacity of cement line and displacement volume to shear wiper plug (SSR).

13.

Theoretical pumping pressures versus slurry and displacement volumes. Prepare a graph.

14.


15.

Nos. of pump strokes at various pump efficiencies, down to 94%.

16.

Maximum possible returns from the cement job, ignoring circulating losses, and the maximum displacement volume required to catch up with the “U”-tubed cement.

17.

Slurry mixing time.

18.

Displacement time.

19.


20.

Theoretical static differential pressure.

21.

Casing test pressure.

22.

Maximum circulating and displacing rates to avoid exceeding a maximum allowable ECD, e.g. leak off test formation strength.

23.

Possible TOC in gauge hole.

24.

Time for bottom plug to bump.

Note: a)

Slurry and displacement volumes are to be calculated by the BP Drilling Supervisor, BP Drilling Engineer and cementer.

b)

Ensure calculated top of cement plus excess does not approach the wellhead.

c)

Be aware of the effects of “U”-tubing which take place during cement jobs. These effects are most noticeable on jobs where there is a large hydrostatic difference between the cement column inside the casing/drillpipe and the mud in the annulus, i.e: - Liner cementations. - Long casing string/large volume cementations. - Large differences in cement/mud weights. During cement mixing/start of displacement, the well may appear to be flowing due to the weight of the cement slurry. A reduction in returns will then occur as the mud “chases” the cement. Full returns should then be regained once the mud has caught up with the cement. It is the responsibility of the Drilling Supervisor to ensure that the Mud Loggers are aware of these effects and that they do not confuse them with flow or losses. If there is any doubt as to whether the well is flowing, it should be flow checked. If losses are apparent the pump rate should be reduced in an attempt to reduce the losses.

2.

CEMENT SLURRIES

2.1

Slurry volume will be based on caliper plus 10% excess.

2.2

If no caliper is available excess volume to be used will be 50% over theoretical volume. Excess to be discussed and agreed with the Drilling Superintendent.

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9 5/8" CEMENTATION

2.3

Excess volumes will be confirmed in the programme. Lead slurry will be class G mixed in seawater with extenders to a weight of 13.2 ppg (1.58 SG). Additives will be specified in the drilling programme and confirmed by cement telex.

2.4

All attempts should be made to ensure that the top of cement is 100m above the previous casing shoe.

2.5

Tail slurry will be a minimum of 150 linear metres of class G cement mixed in seawater to a weight of 16.0 ppg (1.92 SG). Additives will be specified in the drilling programme and confirmed by cement telex.

2.6

The tail slurry must cover and isolate any reservoir or critical zone such as salt, as far as practical.

Note: On surface release cement heads, if the plug drop indicator is partially activated by the bottom plug it should be reset to confirm the bottom plug has gone. 2.7

Ensure that samples of cement slurry are taken regularly during mixing and set aside for observation.

2.8

Top of cement may be confirmed later either by temperature survey or by CBL.

3.

CEMENTING OPERATIONS

3.1

Circulate casing and condition mud using the same annular velocity as when drilling. Record pressures.

3.2

Minimum circulating volume to be the greater of: a)

1.2 times annular volume

b)

1.2 times casing volume

Monitor returns for losses or indications of formation fluid influx, especially gas. If any influx is noted circulation must be continued until a full annulus volume has been pumped without indications of influx. 3.3

Test all cementing lines and equipment to 1000 psi above casing test pressure before circulating.

3.4

If the cement head or cement swivel was not used during circulation install same. Flush cement lines and test hook up to 1000 psi above casing pressure test.

3.5

Pump the preflush as outlined in the programme. If the well is to be suspended then any water based mud and preflush which will remain in the annulus above TOC should be treated with biocide and corrosion inhibitor.

Note: Open hole pressures are to be checked to ensure the reduction in hydrostatic head caused by the preflush will not allow the formation to flow. Use maximum height of preflush in gauge hole for this calculation. 3.6

Surface Release Cementation 1.

After pumping the spacer undertake the following: a)

Install bottom cement plug. Check: i)

Plug is marked as Bottom Plug.

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9 5/8" CEMENTATION ii)

Plug is correct for casing weight and size.

iii)

Plug is below cement line outlet in cement head.

iv)

Passage of plug activates plug drop indicator.

b)

Screw in top plug retainer pin. Lock pin and tie pin lock in position to ensure lock cannot vibrate loose.

c)

Reset plug drop indicator (if possible).

d)

Install top cement plug. Check:

e)

i)

Plug is marked as Top Plug.

ii)

Type of plug manufacture, i.e. all rubber or hollow aluminium.

iii)

Plug is correct for casing weight and size.

Tighten cement head cap.

Note: It is the Drilling Supervisor’s responsibility to witness plug installation. 2.

Release the bottom plug.

Note: If the plug drop indicator is partially activated by the bottom plug, it should be reset to confirm that the bottom plug has gone. 3.

Mix and pump the calculated volume of lead and tail slurry.

4.

Release the top plug when the tail slurry has been mixed and pumped. The Drilling Supervisor is to witness the plug release and plug drop indicator movement. If there is any doubt that the top plug has failed to release, continue displacement checking both the volume pumped and number of strokes.

5.

Ensure cement lines are flushed clean.

Note: When cementing from a floating unit using a full bore running string, a top and bottom plug will be used. 3.7

3.8

Subsea Release Cementation 1.

After mixing and pumping the required lead and tail slurry volumes, release the top plug launching dart with the cement line to the rig floor full of cement.

2.

Pump 2 - 3 bbl of water (or base oil if OBM is being used) to clear the cementing line of cement, followed by the required volume of mud to latch the dart into the SSR wiper plug. This should be done at 4 - 6 BPM to avoid bypassing the dart.

3.

Observe the wiper plug shear (+/- 1850 psi). Change lines at the rig floor to allow displacement with the rig pump.

Displace cement with rig pumps at the highest possible rate, consistent with not inducing losses. Ensure two lines are connected to the cement head to minimize surface pressures.

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9 5/8" CEMENTATION

The displacing volume must be measured from the mud tanks. The return and displacing tank arrangements are to be planned before cement mixing commences either to displace from one tank and return to another or to ensure that a volumetric check is made against pump strokes. Other methods of displacing, i.e. pump strokes, are not accepted as sufficiently accurate to be used as the sole method of displacement volume measurement. Frequent checks must be made on the mud tanks throughout the displacement to ensure that the volume being used compares with the rate of displacement.

3.10

Slow the pumps at the required pump strokes with 100% efficiency, prior to bumping the top plug, and record static differential pressure. If the cement thickening time is approaching ignore above and continue displacement until the plug bumps.

3.11

Bump the plug at a slow pump rate. If the plug does not bump when expected, limit over displacement to half the shoe track volume.

3.12

The maximum number of pump strokes to displace is calculated as: (Actual casing volume + 0.5 x shoetrack volume) x 100/volumetric efficiency (%) x strokes/bbl Discretion must be exercised to ensure over displacement does not occur where isolation around the casing shoe is considered critical. Test casing. Test pressure to be the lesser of: a)

3500 psi;

b)

80% of the internal yield pressure of the casing; or

c)

as advised in drilling programme.

Note and record volume required to reach test pressure. Bleed off pressure and check operation of float equipment. Re-bump plugs if float valves fail to hold, maintain static differential pressure until the cement sets sufficiently to prevent backflow, or until the surface samples set. Release the pressure and check for backflow.

BP EXPLORATION


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7" LINER CEMENTATION AND CLEAN-OUT

1.

7” LINER CEMENTATION

1.1

The 7” liner will normally be run with a three joint shoetrack. The liner overlap will normally be 150m.

1.2

The liner will be cemented in a single stage, using a single slurry formulation. Cement excess will be calculated using 20% excess over open hole caliper volume plus a fixed volume excess equivalent to 100 linear metres of overlap. For short open hole sections not less than 30 bbl of slurry, including excess will be pumped.

1.3

All cementing lines and equipment are to be tested to 5000 psi.

1.4

Send samples of bulk cement (from silo to be used for the job), mix water and additives to the cement contractor for testing at least two weeks before the expected job date. Tests to include thickening time, operating free water, fluid loss and compressive strength at the reservoir and liner lap.

1.5

Install and secure pump down plug in plug dropping head (top drive head if used). Ensure plug has been checked as follows: a)

“O” ring on nose of plug is in good condition.

b)

Plug is correctly sized for DP in use.

Note: 5”/6 5/8” DP should be used to surface. Do not use HWDP. All DP must be drifted to min. 2.875” dia. 1.6

Release liner running tool prior to job as per the appropriate liner setting procedure. Set down required weight on the liner, depending upon the type of liner hanger and sealing mechanism in use. Once the liner is set, begin mixing the cement slurry in the batch tank.

Note: The set down weight must counteract the pump-out loads when the plug is bumped (these forces will be greater if swab cups are used instead of a retrievable pack-off bushing. 1.7

Calculate dp capacity from measurements, i.e. not tabulated values. The recommended procedure is to caliper ten joints to get an average ID.

Note: Allowance should be made for internal upsets. 1.8

Circulate 1.2 times bottoms up. Rotate liner, if applicable. Ensure annular velocity does not exceed drilled annular velocity in open hole section. Monitor returns and ensure well is static.

1.9

Pump preflush. Type, weight and volume to be advised in drilling programme and confirmed by cement telex. Ensure any reduction in hydrostatic head due to height of preflush in gauge hole will not allow the formation to flow.

1.10

Mix cement slurry. Where practical liner cement slurries should be batch mixed in order to ensure accurate additive dosage, homogeneity and correct density. Type, weight and additives to be advised in the drilling programme and confirmed by cement telex. Always use a pressurised mud balance to ensure the slurry weight is correct. Pump slurry.

Note: Observe string weight while cementing. If string begins to hydraulic set down more weight on top of the liner to compensate. 1.11

Release pump down displacement plug. If there is any doubt that the plug has not gone, close Hydril kelly cock, open plug dropping head and check.

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Note: This is only applicable with a cement kelly. This is not applicable when using top drive plug dropping head. 1.12

Displace pump down plug with cement unit until it lands and shears the liner wiper plug. Ensure mud pump is lined up to take over displacement if required. Do not slow down the pump prior to the pump down plug reaching the liner wiper plug, as this has been shown to have a detrimental effect on the cement bond achieved. The liner wiper plug will shear at +/- 1500 psi. Displacement rate will be advised in the drilling programme and confirmed by telex. This will normally be ca. 10 bpm to obtain turbulent flow. Continue displacing until plug lands on the landing collar. Reduce displacement rate to 5 bpm prior to bump. After bumping the plug, pressure test the liner for 10 minutes to the programme test pressure.

Note: If liner wiper plug shear was not observed use theoretical displacement volume only. If it is observed, note the pump efficiency at the shear and use the calculated liner volume from wiper plug to landing collar from the time the shear is seen. Record pre-bump static differential at theoretical displacement volume. Compare with theoretical pressure. No excess should be pumped if plug fails to bump. It is essential that the cement unit operator changes tanks correctly to minimise displacement inaccuracy. 1.13

Bleed off pressures, measure returns, check floats and ensure annulus level is constant.

Note: If backflow occurs, pressure up to see if the plug can be re- bumped. If it cannot POOH. 1.14

If the floats are holding, pressure up DP to +/- 100 psi (only if bump observed). Pull running tool out of hanger, and set integral packer (if run). Note pressure remaining after pulling free. This will provide an indication of the height of cement above the liner.

1.15

Allow DP and annulus to balance. Measure returns.

1.16

Two options may be considered for removing excess cement above liners. Discussion and agreement with the appropriate DS should be in place prior to liner cementation. a)

If Integral Packer has been Run and Set with the Liner Rig up cement hose to reverse out line, close annular and pressure up to +/- 200 psi, pull back slowly until pressure is seen to fall off, pull back clear of liner hanger and complete reverse circulating out excess cement until clean returns observed. Carefully run back into the PBR, 3 to 4 feet. Circulate conventionally and clean out the PBR with the running tool to remove any cement. Note any cement contaminated returns (by circulating with the running tool inside the PBR, a single clean-out trip is possible with a 6” assembly). On deviated wells ensure string is reciprocated and rotated (if possible) during circulation to move cement from low side of hole.

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No Integral Packer Run with Liner Pull to a minimum of 100m above calculated top of cement and conventionally circulate 1.2 x hole contents. Note any cement contaminated returns. (Have all chiksan lines, mud bucket, etc. already rigged up prior to starting cement job in readiness to quickly pull back and rig up for circulating.) On deviated wells ensure string is reciprocated during circulation to move cement from low side of hole.

2.

7” LINER CLEAN OUT Two cases to consider depending on the position of circulation after cementation: Case (a)

Circulation took place above liner lap, no integral packer set.

Case (b)

Circulation took place immediately at top liner with integral packer set.

CASE (a) - Circulation Took Place Above Liner Lap, No Integral Packer Set 2.1

After testing the BOPs, RIH 8 1/2” bit and 9 5/8” casing scraper with a non-rotating rubber sleeve stabiliser (if available). Tag TOC and clean out to the top of the PBR. Condition mud and POOH.

Note: Tag top of the PBR gently to avoid damage to either bit or PBR. 2.2

RIH with 6” bit or mill assembly: 6” bit (or flat bottomed mill), 7" scraper, 6” non-rot stab, 6 x 4 3/4” DC’s, 3 1/2” DP, honing mill, dressing mill, 5” DP.

Note: This assumes that the liner is for production purpose and 6" hole will not be drilled. Have correct spaceout of honing/dressing mill. Honing mill must not bottom out inside PBR before dressing mill reaches top PBR. Space out 6” bit and dressing mill to clean out as close as possible to the landing collar. Exercise extreme caution when entering the liner PBR. Clean out the 7” liner down to the landing collar. Great care is required when polishing/dressing PBR. When entering PBR with honing mill, rotate 40 RPM with maximum circulation. Note when top dressing mill is on top PBR. Very lightly dress top PBR with 2 - 3,000 lbs weight. Note increase in torque. Dress for 2 - 3 minutes only. Pull dressing mill from PBR, leaving rotary table on. This prevents the honing mill scratching vertical scores inside the PBR. Circulate clean. Test CSG/liner as per program, if required. If a CBL/VDL log is to be run, POOH and log the liner and overlap. If no logging is to be undertaken, POOH to above the top of the 7” liner. 2.3

Additional PBR dressing assembly may have to be run if liner packer and PBR are to be set to isolate annulus. Ref. Section 5000. CASE (b) - Circulation Took Place Immediately at Top Liner with Integral Packer Set

2.4

Run the following assembly to clean out 9 5/8” casing and 7” liner in one run: 6” bit - 7” scraper - 6” non-rot stabiliser (if required) - 4 3/4” drill collars - 3 1/2” dp - polish mill spacer top dress mill - 9 5/8” scraper - 8 1/2” non-rot stabiliser (if required) - 5” dp.

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Note: Stabilisers are only recommended in deviated holes. Normal string/NB stabilisers may be run in place of N/R ones. The assembly should be spaced out so that when the hole opener tags the top of the PBR, the bit is ± 10m above the landing collar. 2.5

Circulate clean. Pressure test the liner and overlap as outlined in Section 3550/GEN. The pressures used on this test will depend upon the type of completion to be used. The following outlines the various cases: a)

If a DST is to be run that requires annular pressure response tools, the liner lap should be tested to 1000 psi above the maximum anticipated operating pressure.

b)

If the annulus above the liner lap is to be displaced to a completion fluid of lower density than the mud weight used through the final drilling operation, a drawdown test may be carried out either with a packer or after circulating casing to a lighter fluid. Where possible, this should test the liner lap to a hydrostatic pressure 500 psi below that programmed from the completion fluid. Where a drawdown test is to be carried out, the liner lap should first be pressure tested to 1000 psi above the leak-off pressure at the previous casing shoe.

c)

In all other cases where a well is to be either suspended or tested with mud in the production casing annulus, the liner lap must be tested to 1000 psi above the leak-off at the production casing shoe.

Note: a) A CBL may be required to determine zonal isolation and TOC in the liner lap and/or the 9 5/8” casing. b) If a leak is detected, an RTTS packer may need to be run to identify the source of the leak. 2.6

If the liner lap is leaking, a tie-back packer may be set (refer to Section 5000).

2.7

If required, perform a draw down test using the draw down test string (refer to Section 3560/GEN).

3.

EQUIPMENT CHECK LIST - LINER CLEAN-OUT 1.

1 Nos. 8 1/2” non-rotating stabilisers and/or string stabiliser.

2.

1 Nos. 6” non-rotating stabilisers and/or string stabiliser.

3.

2 Nos. 6” mill tooth rock bits.

4.

1 No. 6” bit breaker.

5.

1 Nos. 6” Economill.

6.

24 Nos. 4 3/4” drill collars (3 1/2” IF conns).

7.

8 Nos. 4 3/4” DC lift subs.

8.

2 Nos. 4 3/4” DC elevator.

9.

2 Nos. 4 3/4” DC slips.

10.

1 No. 4 3/4” DC safety clamp.

11.

1 No. 4 3/4” OD Hydril kelly cock (3 1/2” IF conns).

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12.

1 No. 4 3/4” OD Gray valve (3 1/2” IF conns).

13.

1 No. 4 3/4” OD junk basket.

14.

2 Nos. 4 1/2” reg pin - 3 1/2” IF pin crossovers.

15.

2 Nos. 3 1/2” reg box - 3 1/2” IF box crossovers.

16.

2 Nos 3 1/2” IF pin - 4 1/2” IF box crossovers.

17.

2 Nos. 3 1/2” DP elevators.

18.

2 Nos. 3 1/2” SDXL rotary hand slips.

19.

3 1/2” 13.3 lb/ft S135 drill pipe (3 1/2” IF conns).

20.

3 1/2” drill pipe pup joints (2 x 5m; 2 x 3m; 2 x 1.5m).

21.

12 joints 3 1/2” HWDP.

22.

1 No. 4 3/4” Bowen type Z fishing jar (3 1/2” IF conns).

23.

1 No. 4 3/4” Bowen accelerator (3 1/2” IF conns).

24.

1 No. 4 3/4” Fishing bumper sub (3 1/2” IF conns).

25.

1 No. 5 3/4” Series 150 FS overshot (assembly 8975) c/w 4 3/4”, 4 5/8”, 3 1/2”, 3 3/8” grapples, type A packers and mill controls.

26.

2 Nos. 7” bridge plugs.

27.

1 No. taper mill.

28.

1 No. 7” retrievable packer.

29.

1 No. 9 5/8” retrievable packer.

4.

CALCULATIONS AND REPORTING FOR LINER CEMENTATIONS

4.1

Ensure that the following reports have been completed following the liner cementation:

4.2

1.

Casing log tally.

2.

Casing and cementing reports.

3.

Service company job report.

4.

Pressure recording charts signed by the BP Drilling Supervisor and cementer.

The following 7” liner cementing calculations are to be performed: 1.

Weight of liner prior to hang off.

2.

Minimum circulation volume.

3.

Preflush additive requirement.

4.

Reduction of hydrostatic due to preflush. Use height of preflush in gauge hole.

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5.

Volume of preflush.

6.

Volume of slurry (using calipered ID of liner).

7.

Cement, water and additive requirements for slurry.

8.

Capacity of cement line.

9.

Displacement volume to land pump down plug in liner wiper plug. Note: allowance must be made for the internal upset of the tooljoints. Use measured ID’s.

10.

Displacement volume when cement leaves 7” casing shoe.

11.

Displacement volume to land wiper plug on landing collar (using calipered ID of liner).

12.

Displacement volume when cement arrives at previous shoe.

13.

Displacement volume when cement arrives at casing hanger.

14.


15.

Hydrostatic pressure at previous casing shoe compared to leak off pressure.

16.

Maximum slurry height above liner hanger, assuming gauge hole.

17.

Theoretical differential pressure prior to plug bump.

18.

Theoretical differential pressure when running tool pulled out of hanger with all excess cement in casing.

19.

Maximum allowable circulating and displacing rates to stay within an acceptable ECD, i.e. recognised leak off pressure.

20.

Buoyant running string weight.

21.

Volume required to reverse circulate or circulate the drill string clean conventionally above the top of the liner hanger.

Note: a)

The cement slurry and displacement volumes should be calculated by the Drilling Supervisor, Drilling Engineer (where applicable) and cementer.

b)

Be aware of the effects of “U”-tubing which take place during cement jobs. These effects are most noticeable on jobs where there is a large hydrostatic difference between the cement column inside the casing/drillpipe and the mud in the annulus, i.e: - Liner cementations. - Long casing string/large volume cementations. - Large differences in cement/mud weights. During cement mixing/start of displacement, the well may appear to be flowing due to the weight of the cement slurry. A reduction in returns will then occur as the mud “chases” the cement. Full returns should then be regained once the mud has caught up with the cement. It is the responsibility of the Drilling Supervisor to ensure that the Mud Loggers are aware of these effects and that they do not confuse them with flow or losses. If there is any doubt as to whether the well is flowing, it should be flow checked. If losses are apparent the pump rate should be reduced in an attempt to reduce the losses.

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5"/4 1/2" LINER CEMENTATION AND CLEAN-OUT

1.

5” LINER CEMENTATION

1.1

The 5” liner will normally be run with a four joint shoetrack. The liner overlap will normally be 150m.

1.2

The liner will be cemented in a single stage, using a single slurry formulation. Cement excess will be calculated using 20% excess over open hole caliper volume plus a fixed volume excess equivalent to 100 linear metres of overlap. For short open hole sections not less than 30 bbl of slurry, including excess will be pumped.

1.3

An ancillary pressure/chart recorder is to be used to record the complete operation on a single chart. i.e.

Circulation of liner Pressure test Preflush displacement Cement slurry displacement Pump down plug release Liner wiper plug shear Liner pressure test

This requires a recorder to be fitted to one of the plug dropping head outlets. 1.4

All cementing lines and equipment are to be tested to 1000 psi above the liner test pressure before commencing operations.

1.5

Send samples of bulk cement (from silo to be used for the job), mix water and additives to Fluids Department for testing at least two weeks before the expected job date. Tests to include thickening time, operating free water, fluid loss and compressive strength at the reservoir and liner lap.

1.6

Install and secure pump down plug in plug dropping head. Ensure plug has been checked as follows: a)

“O” ring on nose of plug is in good condition.

b)

Plug is correctly sized for DP in use.

Note: A tapered string of 3 1/2” DP and 5” DP will normally be run. Do not use HWDP. All DP must be drifted to 2.375” dia., including 3 1/2” x 5” x-over. 1.7

Release liner running tool prior to cement job. Set down required weight on the liner, depending upon the type of liner hanger in use. Once the liner is set begin mixing the cement slurry in the batch tank.

1.8

Calculate drill pipe capacity from measurements and not tabulated values.

1.9

Circulate 1.2 times bottoms up. Rotate liner, if applicable. Ensure annular velocity does not exceed drilled annular velocity in open hole section. Monitor returns and ensure well is static.

1.10

Pump preflush. Type, weight and volume to be advised in drilling programme and confirmed by cement telex. Ensure any reduction in hydrostatic head due to height of preflush in gauge hole will not allow the formation to flow.

1.11

Batch mix cement slurry. Type, weight and additives to be advised in the drilling programme and confirmed by cement telex. Always use a pressurised mud balance to ensure the slurry weight is correct. Pump slurry.

Note: Observe string weight while cementing. If string begins to hydraulic set down more weight on top of the liner to compensate.

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1.12

Release pump down displacement plug. If there is any doubt that the plug has not gone, close Hydril kelly cock, open plug dropping head and check.

1.13

Displacement rate will be advised in the drilling programme and confirmed by telex. This will normally be sufficient to obtain turbulent flow without exceeding the fracture pressure, or set the packer. Displace pump down plug with cement unit until it lands and shears the liner wiper plug. Slow the pump down +/- 2 bbl prior to the pump down plug reaching the liner wiper plug, to observe the shear. The liner wiper plug will shear at +/- 1400 psi. Continue displacing until both plugs land on the landing collar. Reduce displacement rate further prior to bump. After bumping the plugs, test the liner to 1000 psi above the observed pressure immediately prior to bump (at reduced rate).

Note: If liner wiper plug shear was not observed use theoretical displacement volume only. If it is observed, note the pump efficiency at the shear and use the calculated liner volume from wiper plug to landing collar from the time the shear is seen. Record pre-bump static differential at theoretical displacement volume. Compare with theoretical pressure. No excess should be pumped if plug fails to bump. It is essential that the cement unit operator changes tanks correctly to minimise displacement inaccuracy. Displacing volume must be checked from the mud tanks. The return and displacing tank arrangement to be planned before cement mixing commences. 1.14

Bleed off pressures, measure returns, check floats and ensure annulus level is constant.

Note: If backflow occurs, pressure up to see if the plug can be re-bumped. If it cannot POOH. 1.15

If the floats are holding, set the CPH packer (refer to Section 2560/GEN) and pull the stinger to just above the PBR.

Note: The running tool cannot be re-engaged. 1.16

Allow DP and annulus to balance. Measure returns.

1.17

Reverse circulate clean. Monitor for contaminated cement returns (if OBM is in use, refer to Section 3780/GEN).

1.18

POOH. Ensure hole is kept full. Monitor fill volume. Do not rotate the string when POOH.

1.19

The following 5”/4 1/2” liner cementing calculations are to be performed: 1.

Weight of liner prior to hang off.

2.

Minimum circulation volume.

3.

Preflush additive requirement.

4.

Reduction of hydrostatic due to preflush. Use height of preflush in gauge hole.

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5.

Volume of preflush.

6.

Volume of slurry.

7.

Cement, water and additive requirements for slurry.

8.

Capacity of cement line.

9.

Displacement volume to land pump down plug in liner wiper plug. Note: allowance must be made for the internal upset of the tool joints. Use measured ID’s.

10.

Displacement volume when cement leaves 5”/4 1/2” casing shoe.

11.

Displacement volume to land wiper plug on landing collar.

12.

Displacement volume when cement arrives at previous shoe.

13.

Displacement volume when cement arrives at the casing hanger.

14.


15.

Hydrostatic pressure at previous casing shoe compared to leak off pressure.

16.

Maximum slurry height above liner hanger, assuming gauge hole.

17.

Theoretical differential pressure prior to plug bump.

18.

Theoretical differential pressure when running tool pulled out of hanger with all excess cement in casing.

19.

Maximum allowable circulating and displacing rates to stay within an acceptable ECD, i.e. recognised leak off pressure.

20.

Buoyant running string weight.

21.

Volume required to reverse circulate or circulate conventionally 500m above the top of the liner hanger.

Note: a)

The cement slurry and displacement volumes should be calculated by the Drilling Supervisor, Drilling Engineer and cementer.

b)

Be aware of the effects of “U”-tubing which take place during cement jobs. These effects are most noticeable on jobs where there is a large hydrostatic difference between the cement column inside the casing/drillpipe and the mud in the annulus, i.e: - Liner cementations. - Long casing string/large volume cementations. - Large differences in cement/mud weights. During cement mixing/start of displacement, the well may appear to be flowing due to the weight of the cement slurry. A reduction in returns will then occur as the mud “chases” the cement. Full returns should then be regained once the mud has caught up with the cement. It is the responsibility of the Drilling Supervisor to ensure that the Mud Loggers are aware of these effects and that they do not confuse them with flow or losses. If there is any doubt as to whether

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the well is flowing, it should be flow checked. If losses are apparent the pump rate should be reduced in an attempt to reduce the losses. 2.

5”/4 1/2” LINER CLEAN OUT The liner will be cleaned out in two stages.

2.1

RIH 6” bit with a non-rotating rubber sleeve stabiliser. Tag top of cement and clean out to +/- 5m above the top of PBR. Condition mud and pressure test the 7” liner, 7”/9 5/8” liner lap (tie-back packer if installed) and 9 5/8” casing. Clean out to the top of the 5”/4 1/2” PBR. Circulate clean and POOH.

2.2

RIH 5”/4 1/2” liner clean out bit or mill. Clean out to the landing collar.

Note: Use extreme caution on trips to prevent damage to the PBR. Space out so that a minimum of 30m is cleaned out below lowest planned perforation. 2.3

Circulate clean and pressure test liner and overlap (refer to Section 3550/GEN). Test pressure to be confirmed. The test will be performed as a leak-off test and should not exceed the leak-off pressure at the previous casing shoe. Note the leak-off pressure required and ensure the 7” liner overlap has been previously tested to above this pressure.

2.4

Set tie back packer if required (refer to Section 5000).

2.5

If required perform draw down test using draw down test string (refer to Section 3560/GEN).

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LINER PRESSURE TESTING

CLEANOUT Clean out liner to landing collar and run a CBL/VDL if necessary. See Sections 3450/GEN and 3500/GEN. Prior to conducting the liner pressure test, circulate the hole clean.

2.

PRESSURE TESTING There are two methods available for liner pressure testing: a) b)

Full Cased Hole Test; Liner Lap Test.

Unless advised otherwise, the full cased hole test will be the normal method of liner testing. 2.1

Cased Hole Test

2.1.1

With the cleanout string above top liner, close pipe rams and pressure up via the kill line to test the cased hole and liner lap to the test pressure advised in the Drilling Programme.

2.1.2

Pressure testing should be conducted as per Leak-Off Testing Section 7100/GEN.

2.1.3

Open pipe rams. Continue with the well programme.

Note: A liner drawdown test may be required (refer to Section 3560/GEN). 2.2

Liner Lap Test

2.2.1

POH with cleanout string.

2.2.2

RIH with Positive Test Assembly as follows: a)

7” Liner Lap Test No.

Item

1 2 3 4 5 6 7 8 9 10 11

Kelly Cock 4 1/2” IF Box/Pin 5” Drillpipe 19.5 lbs/ft 4 1/2” IF B/P 5” HDIS 19.5 lbs/ft 4 1/2” IF B/P Crossover 3 1/2” IF Pin/4 1/2” IF Box 4 3/4” Drill Collars 3 1/2” IF B/P 4 3/4” JAR 3 1/2” IF B/P Safety Joint 3 1/2” IF B/P Crossover 3 1/2” EUE Pin/31/2” IF Box 7” Positrieve Packer 3 1/2” EUE B/P Crossover 3 1/2” IF Pin/3 1/2” EUE Box Wireline Guide 3 1/2” IF Box

Quantity 1 1 1 24 1 1 1 1 1 1

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LINER PRESSURE TESTING

4 1/2”/5” Liner Lap Test No.

Item

Quantity

1 2 3 4 5 6 7 8

Kelly Cock 4 1/2” IF B/P 5” Drillpipe 19.5 lbs/ft 4 1/2” IF B/P 5” HDIS 19.5 lbs/ft 4 1/2” IF B/P Crossover 3 1/2” IF Pin/4 1/2” IF Box 3 1/2” Drillpipe 3 1/2” IF B/P Crossover 2 7/8” IF Pin/3 1/2” IF Box 2 7/8” Drill Pipe 2 7/8” IF B/P 2 7/8” Drill Collars 2 7/8” IF B/P

9 10 11 12 13

Safety Joint 2 7/8” IF B/P Crossover 2 7/8” EUE Pin/2 7/8” IF Box 4 1/2”/5” Positrieve Packer 2 7/8” EUE B/P Crossover 2 7/8” IF Pin/2 7/8” EUE Box Wireline Guide 2 7/8” IF Box

}

1 1 1 1 Sufficient to clear 4 1/2”/5” PBR 1 1 1 1

2.2.3

Set packer immediately below liner hanger.

2.2.4

Close pipe rams and pressure up via kill line to test the cased hole and liner lap to the test pressure advised in the Drilling Programme.

2.2.5

Pressure testing should be conducted as per Leak-Off Testing Section 7100/GEN.

2.2.6

Open pipe rams. POH.

Note: A liner drawdown test may be required (refer to Section 3560/GEN).

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LINER DRAWDOWN TESTING

CLEANOUT Clean out liner to landing collar. See Sections 3450/GEN and 3500/GEN. Circulate the hole clean.

2.

DRAWDOWN TESTING

2.1

Drawdown testing is a technique whereby the integrity of the liner lap is tested in a flowing condition by reducing, in a safe and controlled manner, the hydrostatic pressure inside the overlap to below the pore pressure of the formation outside the overlap. A positive pressure test should be performed prior to conducting a drawdown test. The overlap competence must be proved as during the life of a well the pressure inside the liner overlap may be less than the formation pore pressure outside the overlap. Such conditions may exist when:

2.2

a)

the well is producing with a production packer positioned above or below the overlap; and/or

b)

it is planned to drill out of the liner using a mud weight lower than the pore pressure at the overlap.

The drawdown test will, generally, be determined by the maximum drawdown pressure that the overlap is likely to be exposed to. This drawdown pressure may be large if gas lift is to be used or if there is a failure in the production string. The drawdown pressure must be less than 80% of the collapse rating of the casing and liner. Consideration must also be given to the manner in which the drawdown is applied, i.e. if the test string is wholly or largely evacuated, the drawdown will be applied very rapidly. This could result in shock damage to the overlap. The type and height (if any) of the cushion must be calculated. It is preferred to have fluid to surface for the following reasons:

2.3

-

to allow easier interpretation of the test;

-

to allow the whole string to be pressure tested;

-

to provide easier control if the overlap leaks;

-

to reduce or eliminate shock loading on the overlap by pressuring up the string prior to opening the tester valve.

If drawdown testing is required on a liner, the Well Drilling Programme will advise: a)

BOP/Standpipe/Choke Manifold/Kelly Cock Test Pressure.

b)

Mud Weight in Hole.

c)

Packer Setting Depth.

d)

Length of Water Cushion.

e)

Length of Air Cushion.

f)

Test assembly to be run.

g)

Tester Valve Depth.

Note: Figures 1 and 2 indicate the generalised downhole and surface equipment required to run an effective drawdown test. The equipment will be tailored to individual well requirements. Section 6 indicates a typical test assembly.

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DRAWDOWN TEST ON OVERLAP Procedure

3.1

Ensure that all items required for the test string are onboard and in operable condition.

3.2

Pressure test BOPs, standpipe, choke manifold and Kelly cocks to test pressure as advised in the Drilling Programme.

3.3

Hook up bubble hose to outlet side of choke manifold, line choke manifold up to bubble hose.

3.4

RIH with test string. Ensure the tester valve is in the closed position prior to running in. Partially fill the string every 2 or 3 stands with seawater such that the seawater/air interface is known when the packer is set to give the desired drawdown, as advised in the Well Programme.

Note: The string can be pressure tested at intervals until such time as the string is no longer being filled. 3.5

Go past the packer set-up depth, then come back up to the required depth.

Note: a) Packer setting depth will be +/- 15m above the top of the PBR. b) Ensure that the toolstring is spaced out so that no tools are inside the liner. 3.6

Make up the surface equipment with a kelly cock installed. Pressure test the surface equipment as required against the kelly cock. After testing ensure that the kelly cock is open.

Note: During this time the string will hang and allow the pressure and temperature gauges to stabilise. 3.7

If the test string does not have fluid to surface, the surface lines should be drained and blown dry with compressed air.

3.8

Set the packer.

Note: a) If possible, pressure test the annulus and hold the test pressure for the duration of the test. If the pressure is bled off during the test, allowance must be made for this. b) If the annulus cannot be tested, monitoring of it throughout the test period is essential. 3.9

Depending upon the type of tester valve being used, the valve will either open 2 - 5 minutes after the packer has been set or will require the annulus to be pressured.

3.10

Observe at surface for 30 minutes for any flow.

Note: a) There will be an initial blow/flow from the bubble hose due to the trapped pressure under the packer and the decrease in string volume as the pressure is applied to the annulus. These effects will quickly dissipate. b) There may be a slight temperature effect which will manifest itself as a weak and/or diminishing blow/flow. A constant strong and/or increasing blow/flow will be interpreted as a leaking overlap. 3.11

If the overlap test appears good, close the tester valve for 30 minutes to obtain pressure build-up data to reinforce the bubble hose observations.

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4.

UPON COMPLETION OF THE TEST

4.1

At the end of the 30 minute pressure build-up period, close the kelly cock and line up to reverse circulate.

4.2

Open the kelly cock.

4.3

Drop a bar to shear open the impact sub, or shear out the pressure actuated sub depending on which is being used. Reverse circulate out the seawater cushion through the choke manifold with mud. Circulate 110% annulus contents.

4.4

Stop circulation.

4.5

Unseat the packer.

4.6

Observe the well. If static, break off the line to the choke manifold, pump a pill and POOH.

5.

IF TEST FAILS

5.1

Close kelly cock and line up to reverse circulate.

5.2

Open the reverse circulating sub.

5.3

Reverse circulate out the water cushion and influx through the choke manifold with mud.

Note: Maintain sufficient back pressure to ensure that an additional influx is not taken. 5.4

Observe that the well is static for 15 minutes. Release the packer, flow check again, pump a heavy pill and POOH slowly - observe carefully to ensure that the well remains static and that it is not swabbed in by the packer.

5.5

Examine the charts from the pressure and temperature recorders to determine: i)

that the test has been mechanically successful; and

ii)

that the results reinforce the bubble hose observations.

5.6

To establish the source of the leak, rig up and run a retrievable packer on drillpipe.

5.7

Set the packer immediately below the liner hanger.

Note: The liner integrity should have been established if the plug had been bumped on cementation of the liner. 5.8

Close pipe rams and pressure up down kill line to test the liner overlap to formation leak-off pressure.

5.9

If leakage occurs in the liner overlap, then a programme of remedial operations will be issued.

5.10

If no leakage occurs, repeat the Drawdown Test.

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DRAWDOWN TEST ASSEMBLY (Typical for 7” Liner Drawdown Test) No.

Item

Connections

Remarks

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Circulating Head Kelly Cock 5” Drillpipe Hydrill Drop-in Sub Crossover 4 3/4” Drill Collars Impact Reverse Valve Bar Catcher Sub MFE Valve Hydrostatic Bias Sub Hydraulic Jar Safety Joint Crossover 9 5/8” Positrieve Packer Crossover J-200 Recorder Carrier 3 1/2” Drillpipe Wireline Re-entry Guide

Weco/4 1/2” IF Pin 4 1/2” IF Box/Pin 4 1/2” IF Box/Pin 4 1/2” IF Box/Pin 4 1/2” IF Box/3 1/2” IF Pin 3 1/2” IF Box/Pin 3 1/2” IF Box/Pin 3 1/2” IF Box/Pin 3 1/2” IF Box/4.37 Acme 4.37 Acme/3 1/2” FH Pin 3 1/2” FH Box/Pin 3 1/2” FH Box/Pin 3 1/2” FH Box/3 1/2” EUE Pin 3 1/2” EUE Box/Pin 3 1/2” EUE Box/3 1/2” IF Pin 3 1/2” IF Box/Pin 3 1/2” IF Box/Pin 3 1/2” IF Box

BP BP BP BP BP BP Flopetrol Flopetrol Flopetrol Flopetrol Flopetrol Flopetrol Flopetrol Flopetrol Flopetrol Flopetrol BP Flopetrol

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LINER DRAWDOWN TESTING FIGURE 1 DOWNHOLE TOOLS

IMPACT

PUMP OUT OR PUMP IN OR ROTATION

DRILLPIPE TO SURFACE

DRILLPIPE IS NORMALLY USED FOR DRAWDOWN TESTS ALTHOUGH CONSIDERATION SHOULD BE GIVEN TO USING TUBING ESPECIALLY WHEN THERE IS A POSSIBILITY OF COMMUNICATION WITH A HYDROCARBON BEARING FORMATION AND / OR THE TUBING STRING WILL BE USED SUBSEQUENTLY FOR DRILL STEM TESTING.

DRILL COLLARS/ DRILLING JARS

ENOUGH DRILL COLLAR WEIGHT TO BE RUN TO SET THE PACKER AND OPERATE TOOLS. THE DRILLING JARS ARE ONLY TO BE RUN IF THE DST JARS ARE UNSUITABLE, DO NOT RUN BOTH JARS. ENSURE THE DRILLING JARS WILL ALLOW THE PASSAGE OF THE IMPACT REV CIRC SUB DROPPING BAR.

REVERSE CIRCULATION SUBS

TWO REVERSE CIRCULATION SUBS ARE NORMALLY RUN. SELECTION OF THE SUBS DEPENDANT UPON TESTER VALVE PACKER AND RIG TYPE i.e. FIXED OR FLOATER. ENSURE PUMP OUT PRESSURE IS WITHIN RIG CAPABILITY.

1 x DRILL COLLAR BAR CATCHER SUB

IF APPLICABLE

TEST VALVE

THERE ARE A NUMBER OF SUITABLE TEST VALVES AVAILABLE ON THE MARKET. TWO VALVES WIDELY USED BY BP ARE THE HYDROSPRING AND THE PCT / HRT VALVES, AGAIN TEST VALVE WILL NORMALLY BE FURNISHED BY DST COMPANY.

GAUGE CARRIER

TO BE FITTED WITH AT LEAST 2 PRESSURE RECORDERS AND 1 TEMPERATURE RECORDER. ENSURE PRESSURE GAUGES HAVE BEEN CALIBRATED AT EXPECTED DOWNHOLE TEMP.

JARS/BUMPER SUB

RUN THE DST COMPANY'S JARS IN PREFERENCE TO DRILLING JARS. THE JARS MUST HAVE A JAR UP AND JAR DOWN FACILITY IF NOT A BUMPER SUB MUST BE RUN IN THE APPROPRIATE POSITION.

CIRCULATION SUB

RUN TO SPEED UP TRIPPING, AND REDUCE SWAB PRESSURES.

SAFETY JOINT

THE HALLIBURTON RTTS OR DOWELL POSITEST PACKERS ARE WIDELY USED. ENSURE PACKER ELEMENTS ARE THE CORRECT TYPE FOR SETTING DEPTH TEMPERATURE. PACKER TO BE SET ABOUT 15M ABOVE TOL.

PACKER

PERFORATED TAILPIPE

MAY BE REQUIRED TO BE RUN, DEPENDANT UPON LOWER GAUGE CARRIER.

GAUGE CARRIER

MAY BE RUN IN ADDITION TO OR INSTEAD OF THE CARRIER ABOVE THE PACKER. BOTTOM OF STRING TO BE 3 - 5M ABOVE TOL.

2179 /143

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SURFACE EQUIPMENT

FIGURE 2

CHICKSANS TO TEST/ RIG PUMPS

CONTROL HEAD

BAR DROPPING SUB

LO-TORQ VALVE

DRILLPIPE TO SURFACE

PRESSURE GAUGE, BUBBLE HOSE & NEEDLE VALVES

TO CHOKE MANIFOLD

NOTES: A) THE DRILL STRING MUST BE SPACED OUT IN RELATION TO THE BOP'S. B) THE CONTROL HEAD CAN BE RIGGED UP USING KELLY COCKS, CEMENTING HEAD AND LO-TORQUE VALVES AS REQUIRED. C) THERE MUST BE FACILITIES TO TEST THE VALVES AND LINES USING TEST OR RIG PUMPS, TO PUMP DOWN THE TEST STRING AND TO REVERSE CIRCULATE THROUGH THE CHOKE MANIFOLD. AFTER THE SURFACE EQUIPMENT HAS BEEN PRESSURE TESTED IT SHOULD BE DRAINED FREE OF LIQUIDS, PREFERABLY BLOWN DRY WITH COMPRESSED AIR. D) THE BUBBLE HOSE IS REQUIRED TO MONITOR THE STRING, ESPECIALLY IF THE TOP PART IS EMPTY TO PROVIDE THE CORRECT DRAWDOWN PRESSURE. E) THE PRESSURE GAUGE CAN BE USED TO ASSIST IN THE INTERPRETATION OF THE TEST. F) THE CHICKSANS MUST BE ADEQUATELY RESTRAINED.

2179 /141


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CEMENT PLUGS

CEMENT PLUGS The most successful cement plugs have been set by spotting cement through a tubing stinger with a ported side outlet sub on bottom. Tubing details can be found in Section 3.11 below.

1.1

Plug Checklist and Lessons Learnt Experience has proved the following to have a major impact on setting a successful cement plug: •

Having a base on which to balance the cement plug

•

Correct stinger design

•

Correct temperature selection

•

Accurate displacement

•

Correct slurry volume selection and excess

•

Mud conditioning prior to cementing

•

Mud removal by pipe movement, spacer design etc must be planned

•

Circulating the stinger to prevent plugging

•

Setting the plug in gauge hole

•

For plugs set deeper than 4500m allow for 100m of contamination on top of plug

A simple checklist for planning a cement plug is:

1.2

•

If plug is not to be tagged thickening times in excess of 6 hours are acceptable and job time plus 3 hours recommended.

•

When the hole angle exceeds 30°, either a viscous reactive pill or mechanical barrier should be used to support plug.

•

Mud should be conditioned prior to cementing, typically a 10 minute mud gel and yield point of 20 to 30 is acceptable.

•

The best data for hole size must be consulted, do not assume gauge

•

No cement plug should be set through drillpipe of less than 20bbl for 6" OH or larger

Typical Setting Procedure 1.

Make up and run cement stinger to 100m below plug setting depth (consider to jetting across the interval in open hole)

2.

Spot a viscous pill (Section 2) unless on top of a bridge plug or other mechanical barrier (Section 3.12).

3.

Pull back to plug setting depth and circulate annulus clean.

4.

Pump spacer as defined in Figure 1 and/or cement telex.

5.

Pump cement as defined in Figure 2 and detailed in cement telex, followed by spacer to balance first spacer. Pipe rotation (± 20rpm) will improve cement displacement into the annulus in deviated wells.


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CEMENT PLUGS

Displace at the maximum rate (limited by ECD constraints) to improve gelled mud removal then reduce displacement rate: • •

for hole size < 12 1/4" 2bpm for last 20bbl for hole size > 12 1/4" 3bpm for last 40bbl

7.

Underdisplace by 3bbl excluding the volume of surface lines, unless using a latchdown sub, to ensure that the plug is not contaminated and pipe pulls dry.

8.

Pull back slowly at ± 25 stands/hour to 150m above top of any cement plug which is to be tagged.

9.

Reverse circulate clean provided backpressure does not induce losses or risk differential sticking of string (see Section 3.8).

10. Pull out of hole. 11. Wait on cement prior to tagging or pressure testing as outlined in Section 3.7 below. 2.

VISCOUS PILLS

2.1

Standard Viscous Pills An ordinary viscous pill should be a minimum of 100m. a)

Oil Based Transfer active mud to a pill pit and viscosity to obtain a yield point at least 70 lb/100sq ft. Increase the density to midway between mud and cement density.

b)

Water Based (recommended) The viscous pill should be as thick as possible, with a yield point of at least 70 lb/100sq ft. Increase the density to midway between mud and cement density. Water based viscous pills must not be used for temporary suspension in OH when using OBM/SBM to prevent water wetting of formations.

2.2

Reactive Viscous Pills A 20bbl pill is required for 12 1/4" holes and smaller. For larger hole sizes, use 50bbl. •

A viscous reactive pill depends upon the reaction between calcium and sodium silicate. If the cement plug starts to drop, the calcium in the cement will immediately react with the silicate to form a thick immovable barrier.

•

The pill must not come into contact with any form of calcium on the surface or while being pumped downhole.

• If a weighted spacer is required then the freshwater should be viscosified with XCD and weighted with barytes. For OBM/POBM the spacer recommended on the cement telex should be used. Typically 20bbl ahead with volume behind to balance is used.


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Mixing Procedure for Viscous Reactive Pill Where this is the first use at a particular location a pilot test is recommended. Ensure that the mix water and any fluid remaining in the lines has a calcium level below 400ppm with chlorides below 2000ppm. Treat the mix water with 0.5ppb soda ash to remove the hardness and adjust pH to 9 by the addition of 0.5ppb caustic. Prehydrate the bentonite for at least a hour prior to the addition of sodium silicate (A-3L, D75 or Econolite). If bentonite fails to yield, the drill water is likely to be contaminated. After the silicate is added, the density should be raised to 0.1SG above mud weight. Properties can be adjusted by addition of bentonite or freshwater, with silicate added to maintain concentration. (Silicate can be added directly to the pill in the cement displacement tanks by utilising the LAS system. If this is the case, the silicate should be added during the transfer into the cement tank to assist dispersion. Agitators must also be fitted on the unit, however they may not be too effective if the viscosity is too high.) Typical formulation for an unweighted pill is: 42 gal freshwater + 15 to 25ppb bentonite + 5 gal sodium silicate Typical rheological properties are: Yield Point 50 lb/100sq ft, 10 sec gel 30 to 50 lb/100sq ft

3

RECOMMENDED GUIDELINES WHEN SETTING PLUGS

3.1

Cement Volumes It is preferable to use a calliper log to determine the cement volumes and to help decide where to set a plug (gauge hole recommended). If no calliper is available, the following excesses are to be used unless local knowledge supports different figures: Hole Size (in) 30 to 36 26 to 30 16 to 17 1/2 12 1/4 6 to 8 1/2

% Excess (WBM) 200 100 50 30 30

% Excess (OBM) – – 20 20 20

The actual excess used should take into account knowledge of the particular area and hole conditions, eg sloughing shales or losses. In either case final plug length and contamination indicated in Section 3.6 always needs to be allowed for. Note: Slurry volumes less than 20bbl should not be pumped due to contamination effects. 3.2

Thickening Time and Temperatures 1.

Minimum thickening time should be job time plus a minimum 1 hour safety margin.

2.

Always circulate prior to cementing a minimum of 150bbl or string volume (whichever the greater) to cool the well. Note: Less well cooling occurs when annular fluids are in turbulent flow.


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CEMENT PLUGS

Temperature should be selected based on deviation and operation. It should also take account of local experience. •

For wells below 30° use old API squeeze schedule

•

For wells above 30° the new API temperature equation

•

Wherever hole angle exceeds 60° a temperature simulation using Welltemp (Enertech product) or equivalent is recommended

•

All coiled tubing cement plugs should be designed using Welltemp or equivalent simulation package and unless specific job design dictates have thickening time in excess of 2 x job time or 8 hours whichever is longer

•

In water depths in excess of 500m Welltemp (or equivalent) should be used to predict cooling in riser

It has been general practice to allow some safety margin on Welltemp (or equivalent) designed slurry test temperatures, if no local expertise available add 10°F. 3.3

3.4

3.5

Slurry Properties 1.

Fluid loss is only required in plugs set across permeable formations in hole sizes of 8 1/2" or smaller; a fluid loss less than 150ml is adequate for abandonment/suspension however less than 75ml for squeeze slurries (coiled tubing slurries are special cases and in house experience should be consulted).

2.

Slurry weights and thickening times can be seen in Figure 2.

3.

Dispersant should be used with care to maintain a minimum slurry yield point of 5 lb/1000sq ft.

4.

If losses are occurring consider spotting LCM or including in cement and/or spacer design. Fibrous LCM will act as a cement/retarder.

Slurry Mixing 1.

A batch mixer should be used, if available, to mix all cement plugs. The density should be checked using a pressured mud balance. Once correct density achieved RCM/pump should be shut down.

2.

If the RCM is used, the cement should be brought up to weight prior to pumping. The mixing rate should be controlled at 2 to 4bbl/min. For small cement volumes, less than twice the volume of the RCM, it can be used as a batch mixer.

3.

If the cement is mixed using a jet mixer, it should be dumped overboard until a consistent slurry is obtained.

Cement Plug Displacement 1.

The cement plug should be displaced with the cement unit to ensure accurate control over displacement volume.

2.

The displacement can be accurately determined using either a Halliburton latchdown indicator sub, ball catcher subs or the Dowell PPT tool. In either case the tool provides a positive indication of displacement volume by having a plug catcher sub usually in the drillpipe above the balance point.

3.

When an indicator sub is not used, a slight underdisplacement is desired in order to pull a dry, typically 1 to 3bbl. The average ID of pipe should be determined to ensure correct displacement volume.


SUBJECT: 3.6

3.7

3.8


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CEMENT PLUGS

Cement Plug Length 1.

It should be assumed that the top and bottom 25m of a cement plug will be contaminated with the spacer and will appear to be green cement.

2.

Cement plugs set across perforations should be set from 30m below to 60m above the perforations.

3.

Recommended plug lengths are: •

100 to 180m for 8 1/2" to 36" OH for abandonment, suspension and sidetracking in wells <4500m and <45° inclination

•

For POBM recovery 500m abandonment plugs have been set in 12 1/4" OH for POBM recovery with thickening times in excess of 10 hours

•

In 8 1/2" OH and smaller plugs of up to 250m have been set and successfully tagged to ensure minimum volume criteria is met

•

Plugs in ERD wells are special cases and where plug setting depth exceeds 4500m and hole angle exceeds 45° plug length should be 200 to 250m and allow 100m of contamination on top of the plug

Waiting on Cement and Plug Tagging 1.

Plugs should not be tagged until they have at least 1000psi compressive strength and 1500psi compressive strength is required to pressure test the plug.

2.

Kick-off plugs will require a compressive strength of 3000psi. Deep kick-off plugs (>4000m) across hard formations will require 4000psi compressive strength.

3.

Compressive strength should be determined at a temperature midway between static and the temperature used for designing the pumping time.

4.

Where a plug is being tagged with a kick-off assembly, use minimum flowrates.

5.

Do not run back into a cement plug with the stinger until cement has set. When tagging do not run back into cement without any circulation.

Circulating Clean Pull back at least 150m above top of plug prior to reverse circulating clean if the ECD will not induce losses/differential sticking (this is not required for intermediate plugs set in series). If it is only possible to circulate conventionally the pipe should be flushed clean prior to POOH by displacing 150% pipe contents at maximum rate. In addition to circulating at high rate either drop a dart or pump 50bbl of 50ppb Nutplug/coarse ground marble in active mud to clean pipe from cement rings (wiper balls have also been used, however hardness and temperatures need to be considered). The diverter design needs to be considered in all cases.

3.9

3.10

Cement Spacers 1.

Details can be found in Figure 2.

2.

Always calculate the loss in hydrostatic pressure when using water or base oil ahead of a cement plug assuming gauge hole.

Abandonment Requirements A well abandonment checklist is summarised in Figure 3.


SUBJECT: 3.11

3.12


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CEMENT PLUGS

Cement Stinger 1.

The cement stinger should consist of a tubing stinger; 2 7/8" tubing should be used in slim holes of 8 1/2" or less; 3 1/2" tubing should be used in larger hole sizes. For 17 1/2" OH or larger plugs can be set on drillpipe. Coupling ODs of the tubing should be minimised. If no tubing is available 3 1/2" drillpipe may be considered. Where stinger is to be run through open hole or in casing after a milling operation, break circulation every 5 to 10 stands to prevent plugging of the stinger.

2.

A diverter sub has been proven to improve the success of cement plug setting. To manufacture a diverter sub on the rig, blank off the end of a joint of tubing and cut a minimum eight holes with a minimum 3/4" diameter towards the base of the joint. With a viscous reactive pill or in OBM/SBM, it is essential that two holes are cut around immediately above a blanked stinger minimising the risk of contamination of cement from materials trapped in the diverted sub. Blanking can be considered unnecessary when using a viscous reactive pill or mechanical base.

Mechanical Tools for Supporting Cement Plugs The simplest tool is the BJ Services Parabow which is small sub run on the end of the tubing stinger holding a short ‘umbrella’ like tool which is ‘extruded’ by dropping a ball and ‘springs’ out to up to 20". This can be run in open hole and casing. Inflatable packers can also be used, however these are only recommended inside casing; some of these tools allow inflation and slurry pumping with one trip in hole (eg TAM). Mechanical bridge plugs set on wireline can also be used inside casing.

4.

SETTING PLUGS THROUGH THE DRILLSTRING This is not a routine operation and should only be considered after other options have proved unsuccessful and there is no option to POOH and RIH with conventional cement stinger. The two most likely situations where this approach might be appropriate are during a well control incident, or where total lost circulation has been experienced. The following is the recommended procedure: 1.

Pull the bit back inside the previous casing shoe. If this is not possible, or if the zone to be cemented off is a long way below the shoe, then pull 100m above the top of the zone to be cemented off. Performing this operation with the drillstring in open hole vastly increases the risk of the pipe becoming stuck.

2.

Set the pipe in the slips (rotate the pipe whenever possible if in open hole). Connect the cement pump to the drillstring and break circulation. Line up kill pump on choke manifold.

3.

Close in annular preventer and establish injectivity with cement pump.

4.

Open annular preventer. Pump spacer.

5.

Mix and pump cement followed by 5bbl of spacer using a batch mixer if available and displace with mud until spacer reaches bit. Quickly close the annular preventer with choke closed.

6.

Bullhead the cement down the drillstring to formation, at a convenient rate (c.2bbl/min) until all the slurry has cleared the bit. If there are losses, the bullheading rate should at least equal the loss rate.

7.

If rig-up is possible, immediately inject 5 to 10bbl of mud via the annulus.

8.

Reduce annular preventer closing pressure and pull string back as far as derrick height will allow. Increase closing pressure to former valve.

9.

Wait on cement holding backpressure if required to prevent backflow and rotating the pipe if possible.


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CEMENT PLUGS

10. When cement is considered to have set, circulate either via the choke or, if situation allows, up the riser. Note: In the absence of other data, the cement slurry should be designed at bottom hole static temperature. 5.

CEMENT PLUG REPORTS A cement telex/fax should be sent in after each cement plug has been set. A proforma for this purpose is available in the new reporting manual, PSR-W28.


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CEMENT PLUGS

WBM or OBM? WBM

Pump 40 bbls of water or 100m of annular volume, whichever is smaller (if hydrostatics permit).

If a weighted spacer is required, prepare 30 bbls XCD pill weighted halfway between mud and cement yield point 5 - 10 lb/100 sq.ft. Do not use lignosulphates in spacer.

OBM/SBM

Is plug to be tagged? NO

YES

Pump 20 bbls of base oil or 100m annular length (hydrostatic permitting).

Pump 40 bbls surfactant wash or 100m annular length whichever is smaller (hydrostatics permitting).

If a weighted spacer is required, formulation will be on cement telex.

SPACERS ARE PUMPED AHEAD AND BEHIND CEMENT FOR BALANCING.

Figure 1 Spacers for Cement Plugs


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CEMENT PLUGS

SUSPENSION

TYPE OF PLUG

KICK-OFF

ABANDONMENT NO Will the plug be tagged?

YES

YES Will the plug be tagged?

Use a 1.92 SG slurry, minimum pumping time 2 1/2 hours or job time + 1 hour.

NO

Will the plug be drilled later?

NO

Minimum slurry wt mud wt + 0.1 SG minimum pumping time 4 hours or job time + 3 hours.

YES

Use a minimum 1.58 SG slurry or mud wt + 0.1 SG.

Use minimum of 2.04 SG slurry (or mud wt + 0.1 SG), minimum pumping time 2 1/2 hours or job time + 1 hour.

IF BHST EXCEEDS 230 DEG F, USE CLASS G WITH 35% SILICA FLOUR OR SAND.

Figure 2 Cement Slurry Designs for Suspension/Abandonment/Kick-off Plugs


SUBJECT:


Open Hole • Are there exposed permeable zones? – Do they need to be separated from each other? • Is top zone near to the shoe?

• •

Is there a pressure transition zone that must be secured? Is a sidetrack planned below the last shoe? – Do you need to isolate the old hole? Is there lost equipment in the hole that needs to be isolated (eg contains radioactive isotope) or recovered?

Cased Hole – Perforated • Is there more than one discrete permeable zone? • Is the annulus sealed between zones? • Is recovery of completion equipment necessary to isolate discrete permeable zones? • How high is the planned base of the plug above the top perforation? • Is the formation strength adequate?

Cased Hole – Unperforated • Are there separate discrete permeable zones behind the cased section? – Are they in the same pressure regime? – Is the annulus sealed between zones? • How high is the planned base of the pug above the source of pressure? – Is the formation strength adequate? •

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CEMENT PLUGS Questions to be Asked

•

Section

Is the cement behind the casing sound?

Casing Cut/Liner Lap • Are there ‘exposed’ permeable zones below the cut? Number of Barriers from Surface • Check required number of barriers in place for each source of influx/pressure

Actions to be Taken

If ‘yes’ isolate with cement plug(s).

If not check potential pressure at shoe and set plug above zone, if required. If ‘yes’, isolate with a cement plug over top of transition. If ‘yes’, isolate with cement plug. Recover or isolate adequately.

Isolate internally if ‘yes’. Repair if communication exists. If ‘yes’, retrieve completion and isolate zones.

If not, place cement plug deeper to ensure formation strength adequate.

If not, isolate internally below casing TOC. Squeeze annulus if necessary.

If not, place cement plug deeper to ensure formation strength adequate. If not, repair or ‘cut and cap’/squeeze annulus.

If ‘yes’, isolate with a plug/or squeeze casing/casing annulus.

– –

Two required for hydrocarbon bearing and overpressured formations. One required for normally pressured water bearing formations.

Figure 3 Well Abandonment Checklist


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PARABOW CEMENTING TOOL

INTRODUCTION Parabow is a mechanically actuated cementing tool to assist in achieving accurate balanced plugs in cased or open hole, in sizes from 6in through to 20in. It consists of two umbrella-shaped bows that extend in opposite directions in the wellbore to form a temporary plug upon which cement is spotted.

1.1

Setting Procedure 1.

Make up the tool to running string with 2300ft lbs (2 7/8in EUE connection).

2.

RIH to setting depth. (Run carefully to avoid damaging extrusion tool – maximum speed of one foot per second.)

3.

Prior to going into open hole, establish circulation at pump rate of ±2bbl/min. Continue circulating till tool reaches programmed setting depth, to avoid the possibility of debris entering and blocking the circulating ports.

4.

At depth, rotate and reciprocate 30ft while pumping 50 to 60bbl mud with a maximum pump rate of 5bbl/min.

5.

Drop the activator ball.

6.

Displace the ball at a rate of 3.5bbl/min to extrude the Parabow. (The freefall rate of the 2.5 SG ball may result in the Parabow extruding early.) Extrusion pressure is ±580psi above circulating pressure, but pump rate and fluid properties may prevent full transfer of this pressure to surface. Note:

Do not stop pumping after extrusion of the Parabow unless the pipe is pulled up 7 to 10ft. This is to avoid the compressed fluid in the rat hole pushing the Parabow above the lower circulating port.

7.

Pull up 7 to 10ft while pumping, and increase pump rate to maximum allowable.

8.

Wash entire plug area while rotating, and circulate bottoms up.

9.

Go back to 7 to 10ft above setting depth.

10. Pump spacer ahead, cement slurry, spacer behind, and appropriate volume of mud to balance the plug. Rotate the string while displacing. Consider underdisplacing by 2 to 3bbl. 11. Pull up to ±65ft above the top of the plug. (Recommended pull-out speed ±60ft/min.) 12. Reverse circulate until string is clear of cement, minimum 1.5 times string volume. Maximum recommended pump rate during this operation is ±6bbl/min for 5in pipe. 13. Pull out of hole.

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SQUEEZE CEMENTING

PURPOSE OF SQUEEZE CEMENTING Squeeze cement jobs are required for remedial repair of a primary cement job, to isolate specific intervals or to abandon specific reservoir sections.

2.

CIRCULATION/SQUEEZE REPAIR A circulation/squeeze repair may be required if the primary cement job does not reach part of the annulus and zonal isolation is inadequate. The casing is perforated and cement displaced up the annulus. If no circulation is possible behind the annulus due to a seal higher up then it may be possible to achieve circulation by additionally perforating higher up the casing and circulating cement around the two sets of perforations.

3.

SETTING PROCEDURE a)

Identify the perforation interval required from the cement bond logs.

b)

Run bit and scraper.

c)

Set a drillable bridge plug or viscous pill below zone to be cemented.

d)

Perforate if required.

e)

Set a cement retainer 6m above the squeeze interval.

f)

Stab into cement retainer and establish injectivity using water. Acidize if required.

g)

Pump slurry using water spacers ahead and after the cement. Squeeze cement. Leave at least 15m of cement above the cement retainer.

h)

Pull out of cement retainer and allow cement to equalise. Reverse circulate clean. If there are two sets of perforations pull to above the top set of perforations before reverse circulating clean. It may be necessary to squeeze the top perforations depending upon completion requirements. The remedial cementation can be tested after drilling out the cement retainer.

4.

STANDARD PRACTICES

4.1

Squeeze cementing is usually carried out through a drillable cement retainer, although in some cases a bradenhead squeeze may be an acceptable alternative.

4.2

A squeeze slurry should, ideally, have fluid loss less than 50 ml/30 min. This will help prevent premature hydration and provide better control in directing the placement of cement into channels or voids behind the casing.

4.3

A hesitation squeeze technique should be used to control the build up of cement solids against the formation. The slurry thickening time should be long enough to perform a hesitation squeeze.

4.4

Squeeze pressure should be carefully controlled so as not to exceed a maximum of 85% of fracture pressure.

4.5

Injection rate through perforations should be established using solids free fluid as opposed to mud.

4.6

Before a cement squeeze is undertaken the upward force generated by the pressure in the wellbore should be calculated to ensure that the string weight and annular closing pressure is sufficient to

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SQUEEZE CEMENTING

overcome these forces. At shallow depth, where the calculations show insufficient pipe weight, it will be necessary to lock the string in place with the pipe rams before applying pressure to the wellbore. 4.7

During squeeze cementing operations, the drill floor should be evacuated of non-essential personnel.

Notes 1.

Provided the formation does not fracture, only cement filtrate, not whole cement enters pore spaces.

2.

When the formation is fractured, cement slurry enters as a series of irregular wedges not as one distinct wedge.

3.

Only a small interval of the perforations is likely to be receptive to fluid.

4.

When a packer is used, ensure the bottom hole pressure does not exceed 85% of the collapse pressure of the casing. The packer may have to be repositioned or back pressure applied.

5.

REPORTING

5.1

Pressure and rate for injection test. State type and weight of fluid in use.

5.2

Volume of cement slurry mixed. Type of cement. Type and concentration of additives used. Slurry weight.

5.3

Displacement volume, pressures and rates. Spacer type and volume. (Also report bottom hole pressure vs volume pumped).

5.4

Total volume of cement squeezed/circulated behind casing.

5.5

Insert details on recorder chart.

5.6

Squeeze cement telex to be sent in after squeeze.

6.

TESTING OF SQUEEZED OFF PERFORATIONS The perforations should ideally be inflow tested to evaluate the quality of the shut off. The cement squeeze may be pressure tested, but a positive test is no guarantee of success. Details of the inflow test draw down and time will be provided in the cementing programme.

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LOSSES DURING CEMENTING

1.

Prior to every cement job, calculate the maximum permissible ECD for circulating and cementing the casing. This is particularly important when annular clearances are small, e.g. 13 3/8” casing in 16” hole.

1.1

The mud should be conditioned prior to running the casing to minimise surge pressures and ECD during circulation. Attempts should be made to ensure that the maximum ECD generated when circulating or cementing the casing does not exceed the maximum ECD generated when drilling the hole section. The required rheological mud properties will be stipulated in the drilling programme. In general, the 10 second and 10 minute gel strengths should be similar, and in high angle wells the PV should be higher than 15 and the YP around 25.

1.2

When there have been losses during drilling, or the mud gradient approaches the formation fracture gradient, the ECD while circulating the casing should be calculated at different flowrates and the optimum circulation rate determined.

1.3

Always break circulation slowly to avoid shock loading the formation and monitor for losses. If losses are noted reduce the circulation rate.

1.4

Always establish full circulation prior to landing the casing.

1.5

Casing reciprocation is not recommended once the casing is landed. Maintain optimum flowrate with the casing hung off in the wellhead.

1.6

If losses are severe when circulating prior to a cement job, stop circulating, mix, pump and displace cement.

Note: If the hole is not circulated clean, there is always the possibility of the float equipment or wellhead becoming packed off. However, this may be necessary if large volumes of OBM are being lost. 1.7

Always maintain sufficient mud volume in the pits to displace the casing contents even when total losses have occurred during circulation prior to cementing. However, as a last resort, it will normally be possible to displace the cement using seawater.

1.8

Be aware of the effects of “U”-tubing which take place during cement jobs. These effects are most noticeable on jobs where there is a large hydrostatic difference between the cement column inside the casing/drill pipe and the mud in the annulus, i.e: a) b) c)

Liner cementations. Long casing string/large volume cementations. Large differences in cement/mud weights.

Note: During cement mixing/start of displacement, the well may appear to be flowing due to the weight of the cement slurry. A reduction in returns will then occur as the mud “chases” the cement. Full returns should then be regained once the mud has caught up with the cement. It is the responsibility of the Drilling Supervisor to ensure that the Mud Loggers are aware of these effects and that they do not confuse them with flow or losses. If there is any doubt as to whether the well is flowing, it should be flow checked. If losses are apparent the pump rate should be reduced in an attempt to reduce the losses. 2.

SUMMARY

2.1

Condition the mud prior to running and cementing casing.

2.2

Establish the maximum ECD for the hole section and limit circulating rates accordingly.

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2.3

If excessive losses occur prior to a casing cementation and OBM is in use, cease circulation and begin the cement job.

2.4

During cementing, maintain minimum mud stocks of at least the casing contents.

2.5

Be aware of “U”-tubing effects during cementing.

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CEMENT CONTAMINATED OIL BASED MUD

1.

GENERAL

1.1

It is illegal to dump oil based mud into the North Sea. This includes mud which has been contaminated with green cement or water.

1.2

The possibility of cement contaminated oil based mud being returned at surface can occur in the following operations: 1.

Liner Cementing If cement “U” tubes into the running string after pulling the running tool out of the liner hanger assembly, the cement should fall out as the string is pulled. If an integral packer is set, it is possible to reverse out excess cement. If the cement is to be reversed out, spacer fluid should be incorporated in the displacement such that when the plug bumps the spacer is across the liner hanger/running tool. When an integral packer is not set, the running string should not be circulated. If the string pulls wet, pump only sufficient mud to clear the blockage, followed by a heavy slug. The excess cement will be drilled out. When cement is circulated from above the liner lap, the pipe should be rotated to ensure all cement around the pipe is removed. When it is anticipated that the resulting contamination is less than 10% (see 2.2), it may be possible to incorporate returns into the active mud system. The potential volume from the spacer should also be considered.

2.

Cement Plugs If OBM is in use, do not circulate out any excess cement after setting a cement plug.

3.

Primary Casing Cementations Where casing is being cemented to the wellhead, and excess cement is being pumped as part of the programme, there is always the possibility of the excess being returned to surface. Channelling may also occur, resulting in mud contaminated cement being returned to surface. Casing cementations should be planned to prevent cement contaminated returns at surface. Correct casing centralisation, correct displacement rates and the use of top and bottom plugs will help to minimise channelling.

1.3

If cement contaminated OBM reaches surface, steps will have to be taken to either collect, treat and reuse, or collect, treat and ship ashore, the contaminated mud.

2.

RIG-SITE COLLECTION AND TREATMENT OF CEMENT CONTAMINATED OBM

2.1

The extent of cement contamination in OBM can be measured with a mud balance if the density differential between the mud and cement is large, or by retort analysis.

2.2

OBM contaminated with up to 10% cement will show an increase in rheological parameters and will require circulation through the rig’s solids control equipment followed by treatment with oil-wetting agents and emulsifiers.

2.3

OBM contaminated with between 10 - 40% cement will require treatment by dilution with active OBM, followed by circulation through the rig’s solids control equipment and further conditioning.

2.4

OBM contaminated with more than 40% cement is likely to set solid within a day. Treatment is either massive dilution, circulation through the solids control equipment and treatment, or use of a cement retarder, such as citric acid.

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CEMENT CONTAMINATED OIL BASED MUD

2.5

Effective dilution of the contaminated mud requires prompt action and suitable rig equipment in the form of a header-box flush system and riser charge pump or hole fill pump. It is essential that each rig has the facility available for circulating the active mud, either at the header box or flowline.

2.6

Once dilution has been achieved the OBM can be passed through the solids control equipment as follows: 1.

Direct contaminated OBM return flow over the shale shakers.

2.

Line up the active system and circulate via the header box flush, riser charge or hole fill pumps.

3.

Pump the largest volume of active OBM possible to maximise the dilution.

4.

Run all solids control equipment to remove as much cement as possible.

5.

If possible, pump the sand trap volume via the solids control equipment.

6.

Treat the active system with additional emulsifiers and oil-wetting agents to counteract water influx from the cement.

7.

Keep the system circulating for as long as possible after all cement has been displaced.

8.

If accurate volume control is required the contaminated OBM should be directed to a holding tank prior to dilution and circulation through the solids control equipment.

3.

SUMMARY

3.1

If at all possible, do not allow contaminated cement to be returned to surface.

3.2

If contaminated cement returns to surface are unavoidable, the dumping of neat cement will limit the amount of cement entering the mud system.

3.3

Cement contaminated OBM can be dealt with in the following ways: i)

Dilution and chemical treatment.

ii)

Dilution, passing through the solids control equipment and chemical treatment.

iii) Collection (dilution if necessary), treatment with a suitable retarder and shipping ashore for disposal/recovery.

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EVALUATION OF PRIMARY CEMENTING

EVALUATION OF PRIMARY CEMENTATION The cement job can be evaluated using destructive and non-destructive techniques. Using destructive techniques such as pressure testing and intake testing to check for communication, additional problems can be created during the test. Present non-destructive techniques, using electric logs, such as temperature and accoustic logs, can give an indication of the cement quality. They cannot provide the total answer and should always be used in conjunction with all of the other well data which may be pertinent to the job.

1.1

Temperature Survey Cement generates a considerable heat due to the exothermic reaction while setting. This heat of reaction increases the temperature of the fluid inside the casing which can be measured by a temperature survey. The fluid in the casing should be left undisturbed following completion of the cementation until the survey is made. The log should be recorded running in the hole. The greatest heat is generated while the cement is setting, so the optimum time to run the survey is just after the thickening time, between 6-12 hours after cementing. The amount of heat generated will depend upon the design of the slurry as lightweight slurries generate less heat than neat cement. The temperature survey cannot be used for a quantitative analysis. The tool can only indicate the presence of cement and will not give any indication of bonding. The tool generally only indicates top of cement which could in fact be channelled. Temperature surveys may not be effective when the difference in temperature between the shoe and the top of cement is greater than 70 deg F. The lower temperature higher up the wellbore will delay the onset of the cement exothermic reaction.

1.1.1

Interpretation of Temperature Survey As the sonde is lowered in the hole, the formation temperature gradient will be recorded until an increase in temperature indicates the top of the cement in the annulus. See Figure 1. Below this point the temperature will be affected by the varying cement mass in the annulus which is determined by hole size and the mud displacement efficiency of the cementation. The temperature log should therefore correlate with the caliper log. Lack of correlation probably indicates a poor cement job due to channelling.

1.1.2

Application of Temperature Survey The temperature survey is commonly used to determine top cement where a CBL is not planned or unreliable due to large casing. It is not suitable for the first stage of a two stage cementation because of the delay before drilling out the stage collar and the disturbance of the fluid inside the casing. The production of an accurate CBL/VDL requires tools in perfect condition and a competent logger who pays proper attention to tool centralisation and calibration.

1.1.3

Pressure Recorded Prior to Plug Bump To evaluate the top of cement, the pressure recorded prior to bump can be used. When a lead and tail are pumped the accuracy will be limited, however with a single slurry it will be a reasonable indicator of top of cement.

1.1.4

Further Temperature Anomalies If zonal isolation has not been achieved, fluid movement behind the casing will cause a temperature anomaly. Referring to Figure 2, in the case of gas flow, there will be a cooling effect where the gas leaves the formation. In the case of an upward flow, there would be a heating anomaly of the type shown by the dotted line.

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EVALUATION OF PRIMARY CEMENTING FIGURE 1

TEMPERATURE

FORMATION TEMPERATURE GRADIENT

DEPTH

SUBJECT:

Section

TOP CEMENT

2179 / 202

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,, ,,,, ,,

,,,, ,,,, ,,,, ,,,, ,,,, ,,,,

FIGURE 2

WATER FLOW

,,,, ,,,, ,,,, ,,,, ,,,, ,,,,

GAS FLOW

TEMPERATURE

2179/200

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Cement Log Policy The CBL/VDL is run on all production casings. In all other cases it is run on merit, in view of the ambiguous response of the CBL log and the limitations of the cement evaluation tool, CET, under various conditions and its complicated interpretation. It is essential to run CBL and VDL together especially in the difficult situations listed below. a)

During Drilling If heavy losses occur during cementing of intermediate casings, a temperature survey is to be taken to establish top of cement. This should be 5 - 10 hours after cementing.

b)

During Initial Completion The CBL/VDL will be run in combination with the GR/CCL. A CET should also be run if the mud is not heavily weighted (+/- 1.3 sg WBM/OBM). They will also be run at the request of the drilling office, if there is a good reason for checking the cement bond prior to a remedial squeeze in cases, for example, where high pressures need to be isolated or where there is casing/casing annulus pressure requiring remedial action, based on log results. The combination of CET/CBL/VDL gives a more comprehensive evaluation of cement than the CBL/VDL alone. A CET will resolve cement bonding should a microannulus be present as it is unaffected by narrow channels which constitute microannuli.

c)

Before Workovers If requested, a CBL/VDL/CET can be run if there is reason to believe that unusual production of gas and/or water originates from an adjacent reservoir, and if a remedial squeeze will be attempted. The CET can caliper the casing.

d)

Prior to Cutting and Retrieving Casing (for example to sidetrack) At the request of drilling office a CBL/VDL/CET will be run to indicate whether a cement bond is higher than theoretical top cement, due to channelling, and in addition to give an indication of formation collapse.

1.2.1

Guidelines for LOG Evaluation a)

CBL/VDL Log Quality The following conditions are essential for a reliable CBL/VDL log: 1.

Casing sizes preferably 9 5/8” or less.

2.

Good centralisation. At least 3 centralisers must be used. The transmitter and receiver must be within 1/8” of the pipe centre. The centralisers must be close fitting ± 1/8” of pipe internal diameter and are to be Gemco spring types. They are almost rigid and therefore are tight fitting so that in directional holes it is usual to mount 3 on the sonde with the rest of the tool free in the pipe connected by a knuckle joint. In vertical holes it is simpler to centralise the tool string completely. At lease one of the centralisers must be mounted within one foot from the sonic transmitter receiver pair.

3.

On deviated wells the CBL/VDL must be centralised and run specifically across each casing string separately, ie the tool should be centralised for 7” liner and logged across the liner. New centralisers must be installed to log the 9 5/8” casing.

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EVALUATION OF PRIMARY CEMENTING On vertical wells, it is possible to obtain a reasonable log across both 7” and 9 5/8” casings in one run provided the stronger spring centralisers are used. This would have to be specified to the logging contractor prior to running the log. The log quality would not be as good as those run separately and must be considered when evaluating the log.

4. b)

c)

Downhole calibration to take place in unbonded pipe if available.

CET Log Quality 1.

The CET requires a playback to be made - instant (real time) log are often incorrect and need recalibrating.

2.

The tool eccentricity must be less than 1/4”.

3.

Generally cement quality should agree with the CBL.

4.

The 4 calipers should agree, within 1/8” and likewise the ovality should be less than 1/8”.

5.

Black flags (measurement not reliable) should be not more than 1 per foot, except in overlapping casings.

6.

Free pipe should show white.

7.

Can only be used in light muds because solid particles (barytes) interfere with the high frequency sound waves.

Evaluation of Primary Cementation - CBL i)

Channelling Microannulus Poor Cement and Uncentred Pipe are all characterised by a decrease in formation signal and an increase in casing signal. Microannulus is frequently present and is not a cement failure whereas channelling is. They can be distinguished only by applying pressure to the inside of the casing, or with a CET. If any remedial work is being considered because of a poor CBL then the log should be rerun with pressure on the casing. This will determine if lack of cement on the CBL is only due to a microannulus. Microannulus is commonly created by displacing heavy mud with a less dense brine before logging as well as by temperature rise during setting.

ii)

Good Bond between pipe and cement but poor bond between cement and formation is characterised by weak casing arrival and weak or no formation arrival. VDL is essential here to indicate the lack of formation response.

iii) Hard Formations (Anhydrite and Dense Limestones) having high velocities are characterised by formation arrivals preceeding the casing arrivals (travel time less than 57 micro sec/ft). This case will not occur in soft deltaic deposits. Can be identified on VDL. iv) Free Pipe eccentred and rested against formation is characterised by both strong casing and formation arrivals, which are not apparent in the 4 previous cases. d)

Evaluation of Primary Cementation - CET i)

Channels are seen as the whole pipe circumference is scanned: - Eccentred pipe appears well cemented. - Microannulus is seen as good cement (which it is) unless > 0.1”, which is very rare.

Microannulus is commonly created by displacing heavy mud with a less dense brine before logging as well as by temperature rise during setting.

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EVALUATION OF PRIMARY CEMENTING Good Bond appears as good cement.

iii) Hard Formations may show free pipe, but will be flagged. iv) Free Pipe might appear as cement on one side. v) e)

CET only examines the cement casing bond, it is unable to identify a channel if it does not extend to the casing.

Log to be run at least 36 hours after cement job.

Notes:

1.2.2

-

In a 9 5/8” casing for zonal isolation a good bond (Bond Index 0.8) over a continuous interval of greater than 15 feet is required.

-

The tool must be very well centralised and additional centralisers are required (at least five for the CBL/VDL/CCL/GR combination), in deviated hole.

Interpretation The CBL is a measure of Cement Bonding, and not cement presence. The two extreme cases, i.e. unbonded free pipe and well cemented pipe 100% surrounded by cement, can be easily recognised from the CBL log, as indicated by the waveform graph.

1.2.3

Free Pipe is characterised by strong casing signals which give:

CBL a) b) c) d) e) f) 1.2.4

High CBL readings. Parallel lines on VDL vs depth. Weak formation signals. Clear chevron pattern “W” at collars on the VDL. No change in transit time with depth. White.

a) White on map. b) CSMX, CSMN are zero. CSMX = Max Cmt Strength. CSMN = Min Cmt Strength.

Good Bond is characterised by strong formation signals which produce:

CBL a) b) c) d)

1.2.5

CET

Low CBL readings. Casing signals very weak. Strong formation arrivals on VDL (provided formation attenuation is not too high, e.g. gas sands). Formation arrivals change in pattern with depths in contrast to casing arrivals which give parallel lines. In shales there is often a correlation between GR and VDL.

CET a) Black on map. b) High CSMX, CSMN.

In the cases listed below the CBL reading is in between good bond and free pipe levels. The CBL alone cannot separate one case from another. Combination with the VDL is essential and therefore it is always policy to run CBL and VDL together. a)

CBL Channelling Microannulus Poor Cement and Uncentred Pipe are all characterised by a decrease in formation signal and an increase in casing signal. Microannulus is frequently present and is not a cement failure whereas channelling is. They can be distinguished only by applying pressure to the inside of the casing, sufficient to close the microgap and logging with the gap closed. However, this may not work as a microannulus commonly forms a hydraulic seal. In addition, pressure control equipment would be required.

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b)

Good Bond between pipe and cement but poor bond between cement and formation is characterised by weak casing arrival and weak or no formaton arrival. VDL is essential here to indicate the lack of formation response.

c)

Free Pipe eccentred and resting against formation is characterised by both strong casing and formation arrivals, which are not apparent in the 4 previous cases.

FIGURE 3

57 µ SEC/FT.

TIME ZERO

A - FREE PIPE

B - GOOD BOND TO PIPE AND FORMATION 50 FT. FORMATION (LOW VELOCITY)

C - GOOD BOND TO PIPE AND HARD FORMATION (FAST VELOCITY)

D - GOOD BOND TO PIPE NO BOND TO FORMATION

FORMATION ARRIVALS CASING ARRIVALS



Index Prefixes 0000


1000

Drilling

2000

Casing and Tubing

3000

Cementing

4000

Drilling Fluids

5000


6000


7000

Well Evaluation

8000






Section

Description

4000

DRILLING FLUIDS

4000/GEN

Drilling Fluids - General

4100/GEN

Spud Mud

4110/GEN

Prehydrated Bentonite Premix

4120/GEN

Bentonite Polymer Mud

4130/GEN

Gypsum/Polymer Mud

4140/GEN

Seawater Polymer Mud

4150/GEN

KCI Polymer Mud

4160/GEN

Inverse Oil Emulsion Mud

4170/GEN

Salt Saturated Mud

4200/GEN

Barytes Plug - Water Based Mud

4250/GEN

Barytes Plug - Oil Based Mud

4300/GEN

Lost Circulation

4400/GEN

Contamination of Drilling Fluids

4500/GEN

Mud Testing

4600/GEN

Solids Control

4900/GEN

Drilling Hydraulics


SUBJECT:


4800/CLY

Pit System Clyde

4800/BEA

Pit System Beatrice

4800/MIL

Pit System Miller


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@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@LN@@@@@e?@@@@?g?J@@@@@@@@5?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@1?@@@@@e?@@@5?e@?e?7@@@@@@@@HJ@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@W@@@@5e?@@0Y??J5?e?3@@@@@@@5?7@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@Y@@(YhO&H?e?N@@@@@@@HJ@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@W@@Y?gO2@@g@@@@@@5?7@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@Y@@@@@@@@@@@@@@@@@@@@@@@@@HJ@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@W@@@@@@@@@@@@@@@@@@@@@@@@@T&@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@UI4@@@@@@@@@@@0MS@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@)K?W@@@@@@@@0M?O&@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@YW@@@@0M?O2@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@YW(M?O2@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@YO2@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?

BP EXPLORATION


Section

:

4000/GEN

Rev.

:

2 (11/89)

Page

:

1 of 2

DRILLING FLUIDS - GENERAL

FUNCTIONS OF DRILLING FLUIDS Drilling fluids have been steadily increasing in complexity to better cope with the different formations drilled and increased depths, but for any mud, the nine basic functions are:

1.1

a)

To remove the drilled cuttings from the hole.

b)

To control sub-surface pressures.

c)

To cool and lubricate the bit and drillpipe.

d)

To prevent the walls from caving.

e)

To release the drilled cuttings at the surface.

f)

To prevent damaging effects to the formation penetrated.

g)

To allow maximum information from the formations penetrated.

h)

To suspend the cuttings and weight material when circulation is stopped.

i)

To help suspend the weight of the drill string and casing.

Removal of Cuttings Several factors contribute to the effectiveness of removing cuttings from the borehole. a)

Annular Velocity As the mud is circulated up the annulus, the cuttings tend to fall at a certain slip velocity depending on their density, shape and size. The annular velocity must be higher than the slip velocity.

b)

Rheology As the viscosity of the mud is increased, then the better the lifting capacity of the fluid.

c)

Mud Density By increasing the density of the mud, the cuttings become more buoyant, resulting in cleaner flow.

1.2

Controlling Sub-Surface Pressures The pressure of the mud column should be greater than that exerted from the formation whether these pressures are due to oil, gas or water. The hydrostatic pressure of the mud is of prime importance, but other considerations should be observed such as keeping the hole full during trips and maintaining low gel strengths to prevent swabbing whilst pulling pipe.

1.3

Cooling and Lubricating Considerable heat can be generated due to friction while drilling. The mud lubricates the bit and forms a coating around the drillstring to reduce friction. Heat is also dissipated by the mud as it is circulated. Special additives can be added to the mud to further increase its lubricity.

1.4

Preventing the Walls from Caving Over permeable formations, a thin tough filter cake is formed. This filter cake can be improved upon by adding colloidal material such as bentonite and other chemicals to produce a firmer cake. The deposition of the filter cake tends to line unconsolidated formations and to retard invasion of the fluid. In troublesome shale areas, the lowering of fluid invasion may lessen the caving or sloughing of these

@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@0M?fI4@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@0M?g?O2@6KhI4@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?e?O2@@@@@@@@@@@@@@@@@6Kf@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?@@@@@@@@@@@@@@@@@@@@@@@@@@@?@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@5?@@@@@@@@@@@@@@@@@@@@@@@@@@@W@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@HJ@@@@@@@@@@@@@@@@@@@@@@@@@@@@Y@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?7@@@@@@@@@@@@@@@@@@@@@@@@@@@@?@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?@@@@@@?g?I'@hI'@@?3@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@5?@@@@@@?hN@L?g?N@@LN@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@HJ@@@@@@?e@@6Xe?@1?e@@6Xe3@1?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?7@@@@@@?e@@@1e?@@??J@@@1eN@@?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?@@@@@@@?e@@@@e?@5??7@@@5eJ@@?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?@@@@@@@?e@@@5eJ@H??@@@@He7@@?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?@@@@@@5?e@@0Ye7@e?@@@@?e@@@?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?@@@@@@H?h@@he@@@?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?@@@@@@e?@@@@?e3@g?O2@@@@?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?3@@@@@e?@@@@?eV'f@@@@@@@@@?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@LN@@@@@e?@@@@?g?J@@@@@@@@5?@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@1?@@@@@e?@@@5?e@?e?7@@@@@@@@HJ@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@W@@@@5e?@@0Y??J5?e?3@@@@@@@5?7@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@Y@@(YhO&H?e?N@@@@@@@HJ@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@W@@Y?gO2@@g@@@@@@5?7@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@Y@@@@@@@@@@@@@@@@@@@@@@@@@HJ@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@W@@@@@@@@@@@@@@@@@@@@@@@@@T&@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@@@@@@>@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@UI4@@@@@@@@@@@0MS@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@)K?W@@@@@@@@0M?O&@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@YW@@@@0M?O2@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@YW(M?O2@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@YO2@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@? @@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@@?

BP EXPLORATION


Section

:

4000/GEN

Rev.

:

2 (11/89)

Page

:

2 of 2

DRILLING FLUIDS - GENERAL

shales. The hydrostatic pressure exerted by the column of mud also helps to stabilise the hole and prevent the wall caving. 1.5

Suspending and Releasing Cuttings When circulation is stopped, then the mud should be capable of suspending the cuttings and any weight material, but it should also be able to release the cuttings at the surface, thus preventing them being recirculated. To do this, the mud must have a gellation property when stationary and become fluid again upon movement. This property can be altered by changing the colloidal content and altering the chemical treatment thereby affecting the attractive forces of these colloids.

1.6

Preventing Damage to Wellbore and Securing Maximum Hole Information After drilling the hole, the mud should not cause interference with the evaluation of the hole and should allow the reservoirs to be produced with the maximum protection and least damaging effects.

1.7

Supporting Weight of Drillpipe and Casing The buoyancy effect of the mud supports the drillpipe and casing. Increased weight results in less weight that the surface equipment has to support.

BP EXPLORATION


Section

:

4100/GEN

Rev.

:

2 (11/89)

Page

:

1 of 2

SPUD MUD

USE OF SPUD MUD Drilling of large surface holes results in low annular velocities. In order to remove the cuttings, which are fairly large at these shallow depths, high viscosity mud is used.

1.1

Drilling Without Returns Seawater with 30-50 bbl viscous slugs per 10 metres drilled or as required for hole cleaning is used. On reaching casing depth, the hole is circulated to viscous mud.

1.2

Guar Gum in Seawater 2.5 ppb 3.0 ppb 3.5 ppb

YP YP YP

45 60 85

Funnel Viscosity Funnel Viscosity Funnel Viscosity

85 125 250

If the guar gum slurry is to be left on surface for a period greater than 12 hours, it should be treated with 500 ppm Proxel GXL (Biocide) to prevent fermentation.

Note: Caustic additions should not be made with guar gum. 1.3

Pre-Hydrated Bentonite Soda Ash Caustic Bentonite

0.2 ppb 0.5 ppb 25 - 30 ppb

This should yield a funnel viscosity in excess of 100 sec/qt. Should a further increase in viscosity be required, 0.2 ppb lime can be added to flocculate the slurry just prior to its use. Lime should not be added to pre-hydrated bentonite that is to be left in the hole prior to running casing as the lime will eventually result in loss of viscosity resulting in possible hole fill. 1.4

Advantages of Each System The main advantage of guar gum is that it can be mixed in seawater and hence drill water shortages are not a problem. It does not however form a good wall cake and hence does not provide fluid loss control. Pre-hydrated bentonite requires drill water and 6-8 hours hydration time. A fluid loss of less than 20 cm3 can be expected with this mud. When guar gum is used for sweeping the hole whilst drilling, it is preferred that the hole is displaced to a pre-hydrated bentonite slurry prior to running the casing for increased hole stability.

2.

DRILLING WITH RETURNS A bentonite slurry formulated from pre-hydrated bentonite premix and seawater is used when drilling with returns.

2.1

Composition Pre-hydrated Bentonite Seawater Caustic Hi Vis CMC

15 - 20 ppb 0.5 ppb 1.0 - 2.0 ppb

BP EXPLORATION


Section

:

4100/GEN

Rev.

:

2 (11/89)

Page

:

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SPUD MUD

General Properties Funnel Viscosity Yield Point Fluid Loss pH Mud Weight

50 - 60 sec/qt 25 - 30 lbs/100 ft2 < 20 cm3 9.5 - 10.0 As low as possible (1.11 SG is the normal minimum annulus return weight that can be expected).

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PRE-HYDRATED BENTONITE PRE-MIX

USE OF PRE-HYDRATED BENTONITE PRE-MIX Bentonite is added to water base mud in areas where no “mud making” clays are to be drilled. It improves the filter cake quality and reduces the fluid loss. It also increases the yield point and hence the carrying capacity of the mud. As bentonite will not yield in seawater, it is pre-mixed in fresh water and then added to the seawater based mud. This results in the initial flocculation of the bentonite but this will shear back through the bit. To reduce the “viscosity hump” and to slow the rate of de-hydration of the bentonite, the pre-mix is treated with Chrome-Free Lignosulphonate (CFL) or a Hernative dispersant such as CF Desco or polyacrylate.

2.

PREPARATION OF PRE-MIX a)

Treat the drillwater with 0.2 ppb soda ash to reduce the total hardness. Adjust pH to 10.0 - 10.5 with caustic.

b)

Add 30 - 35 ppb bentonite.

c)

Allow to hydrate for 6 - 8 hours.

d)

Add 2 - 3 ppb chrome free lignosulphonate or alternative dispersant.

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BENTONITE/POLYMER MUD

USES OF BENTONITE/POLYMER MUD This system is used for “simple” drilling areas where no formation inhibition is required. The mud is easily prepared and maintained. The main constituents are as follows:

2.

3.

4.

a)

Pre-Mixed Bentonite. This provides the yield point for the system and the basis for fluid loss control.

b)

CMC LV. Low viscosity CMC is used for additional fluid loss control.

c)

CMC HV. High viscosity CMC is used for increasing the viscosity of the system. It is also effective in reducing the fluid loss.

d)

Chrome Free Lignosulphonate. This is not added to the initial formulation but is used to control any progrssive gel strengths that may occur.

COMPOSITION a)

Seawater

b)

Pre-hydrated Bentonite Pre-Mix

15.0 - 20.0 ppb

c)

CMC LV

1.0 - 2.0 ppb

d)

CMC HV

0.5 - 1.5 ppb

e)

Caustic

0.5 ppb

ADVANTAGES a)

The mud is cheap and easy to maintain.

b)

It has a high solids tolerance.

DISADVANTAGES a)

The mud has no inhibitive properties.

b)

As the system is very lightly treated, it is susceptible to contaminants.

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GYPSUM/POLYMER MUD

USES OF GYPSUM/POLYMER SYSTEMS A gypsum/polymer mud is a moderately inhibitive mud system used for drilling shales or massive anhydrite sections. Gypsum is a source of calcium ions which base exchange with the sodium ions of the clays. The divalent calcium ion results in a greater attractive force between the clay platelets pulling them closer together and increasing the volume of “Free” water. The combination of the reduced size of the clay particle and increased “Free” water results in reduced viscosities and increased solids tolerence.

2.

COMPOSITION The system is essentially designed to be run non dispersed. a) b) c) d) e) f)

3.

4.

Seawater PAC EX Polymer Starch Caustic Gypsum

1.5 - 2.0 ppb 0.3 - 0.5 ppb 2.0 - 4.0 ppb 1.0 ppb 4.0 - 6.0 ppb

NOTES ON RUNNING A GYPSUM/LIGNOSULPHONATE MUD a)

The pH should not be increased above 10.5 as this will limit the calcium solubility.

b)

The alkalinity will decrease with gypsum additions.

c)

The mud will often foam whilst mixing. Aluminium Sterate can be used to counter this. The product is water insoluble. It is therefore mixed at approximately 1.5 lbs per gal in either base oil or diesel. Two or three Marsh Funnel cups is usually sufficient to cure the problem.

d)

When this system is used to drill highly reactive 17 1/2” “gumbo” sections, massive dilution will be required. This can be of the order of 4.9 - 6.5 bbl/metre or 150 - 200 bbl/hr in extreme cases.

e)

As the solubility of gypsum is low, an excess is maintained so that the calcium in solution is replaced as it is consumed.

f)

The level of excess gypsum should not be allowed to deplete or a viscosity “hump” will be experienced with further gypsum additions.

BREAKOVER TO A GYPSUM/POLYMER SYSTEM If it is deemed necessary to change over a non-inhibited mud system, the following procedure should be adopted to minimise loss of control of the mud properties. When gypsum is added to a mud containing sodium exchanged clays, severe flocculation with a large increase in viscosity will occur followed by a decrease in viscosity as the clays aggregate. This “hump” can be nerve racking when first met. Its severity will depend on the nature of the clays in the mud. The breakover is best carried out over two or three circulations.

4.1

1st Circulation Reduce funnel viscosity to approximately 35 and MBT to 12-15 ppb.

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GYPSUM/POLYMER MUD

2nd Circulation Add gypsum and caustic. A dispersant, either chrome free lignosulphonate, CF Desco or a polyacrylate, may also be required.

4.3

3rd Circulation Add PAC, XC Polymer and starch to adjust YP and fluid loss to the desired properties. Note When calculating the number of sacks of gypsum required, 20% over the calculated value should be used because of the base exchange adsorbance of the free calcium. In some circumstances, it will not be possible to reduce the viscosity of the mud prior to making the conversion because of mud weight considerations. Under these conditions, conversion should be made in one circulation: a)

During the conversion, agitate only the suction pit. This should be gunned if possible. Backflow between the suction and return pit should not be used.

b)

Start caustic additions directly to the suction pit mixing dispersant through the hopper if necessary.

c)

If at any stage, the mud becomes too viscous, the dispersant additions should be increased.

d)

Once all the gypsum has been added, the polymer additions can be made to adjust the mud to the desired properties.

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SEAWATER POLYMER MUD

USE OF SEAWATER/POLYMER MUD The seawater/polymer mud is a low solids, non-dispersed system based on three types of polymer: a)

PAC (Polyanionic Cellulose). A multipurpose polymer which provides viscosity, fluid loss control and some shale inhibition by encapsulation.

b)

X C Polymer. This polymer is used at low concentration to increase the yield point whilst having little effect on the plastic viscosity.

c)

Modified Starch. This is for further fluid loss control. The product has a biocide blended in to prevent fermentation.

This system is ideal for exploration wells as it is flexible in that it can be quickly converted to a more inhibitive system or salt saturated if required. Its low “n” value or high YP/PV ratio give it good hole cleaning properties. 2.

COMPOSITION Seawater Soda Ash Caustic PAC X C Polymer Modified Starch/ or Lo Vis CMC

3.

1.0 ppb 1.0 ppb 1.5 - 2.0 ppb 0.25 - 0.5 ppb 2.0 - 6.0 ppb

TREATMENT a)

PAC and Lo Vis CMC are suspect to precipitation by calcium at high pH (greater than 11.5). To prevent this, the calcium level in the seawater should be reduced to less than 250 mg/L with soda ash prior to adding the polymer. The pH of the system should be run at 9.0 - 10.0.

b)

The MBT should be controlled below 20 to prevent excessive gel strength development.

c)

Above a mud weight of 1.40 SG, it is dificult to run this system without dispersant due to high gel strengths.

d)

As the polymers require shear to dissolve fully, they should be premixed into seawater before addition to the mud system. Adding the polymers on the run can result in “fish eye” formation with the polymer being removed at the shakers.

e)

As the system is non dispersed, it is not very solids tolerant. It is therefore essential that good solids control is practiced if the system is to be economical.

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KCL/POLYMER MUD

USE OF KCL/POLYMER MUD This is highly inhibitive mud used primarily for drilling reactive tertiary claystone sections. It can also be used to drill older Illite shales where the problem is one of sloughing and cavings rather than “gumbo” type problems. The system is based on the inhibitive effects of the potassium ion combined with the inhibiting effects of a long chain polymer. The polymer, a hydrolysed co-polymer of Polyacrylamide and Polyacrylate with a molecular weight of 10 million, forms a viscous gelly like coating that seals pores and fissures slowing down the movement of water into the shales. The viscosity of the mud is controlled with XC polymer. Fluid loss control can be obtained with starch additions.

Note: This is a non-dispersed system and dispersant should only be added when control of the properties by dilution has become uneconomical. 2.

FORMULATION Seawater Caustic KCL Hydrolysed Polyacrylamide XC Polymer Starch

2.1

1.0 ppb 15.0 - 50.0 ppb 1.0 ppb (Active) 0.25 ppb 2.0 - 4.0 ppb

KCL Concentration Depending on the reactivity of the shales, concentrations of up to 50 ppb may be required. When drilling older shales 15 ppb may be sufficient. An average concentration is 35 ppb.

3.

RUNNING A KCL/POLYMER SYSTEM a)

To ease logistics, KCL is usually supplied as a brine. This is a nominal 80 ppb (1.15 SG). However, due to the difficulty in mixing to this level, the concentration is nearer to 80 ppb (1.12 SG).

b)

When mixing the system initially, high shear is required to dissolve the hydrolysed polyacrylamide. If this is not possible, then very coarse shaker screens should be run for the first circulation to prevent losses due to screen blinding.

c)

If a KCL concentration of 35 ppb is required, then the initial mud should be mixed to 40 ppb as it will be found that the concentration drops rapidly on the first circulation.

d)

KCL and polyacrylamide concentrations can be measured by specific tests. It may be necessary to add both on “the run”, to maintain the desired concentrations although it is highly desirable to premix all polymer additions. This is due to adsorption on to the shales. As a guide line 1 x 25 ltr drum of hydrolysed polyacrylamide should be added to the active system for every 30m of 17 1/2” hole drilled.

e)

When adding polyacrylamide, it should be added directly into the suction pit above the suction to prevent “viscosity humping”.

f)

An excess polyacrylamide concentration of 0.5 ppb should be run.

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KCL/POLYMER MUD

g)

The MBT maximum for this system is 20 ppb. Above this, control of the rheological properties will become difficult.

h)

At mud weights above 1.40 SG, it is very difficult to run the mud non- diserpsed.

MERITS OF THE KCL/POLYMER SYSTEM This is an expensive mud system at approximately twice the cost of a Gypsum/lignosulphonate system. It cannot tolerate the solids that a Gypsum/lignosulphonate system can (max MBT, 20 ppb and 30 ppb respectively) but the inhibitive properties are far superior to the Gypsum/lignosulphonate system. Downtime from blocked flowlines etc. should therefore be less with KCL and hence only with area experience will it be possible to say if the increased cost of the mud system is more than offset by rig time saving and possible better hole caliper. It must also be remembered when considering downtime from gumbo problems, that part of the problem may be due to a mixture of drilling practices, hole cleaning and flowline design as much as to mud chemistry. The mud described above is the “full” system. However, it can be run without the polyacrylamide which will make a cheaper system. However, area experience will again dictate if this is cost effective.

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KCL/POLYMER MUD




2.1



3.



b)


c)


d)


e)


f)


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KCL/POLYMER MUD

g)


h)



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2.1



3.



b)


c)


d)


e)


f)


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KCL/POLYMER MUD

g)


h)



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INVERSE OIL EMULSION MUD

USES OF INVERSE OIL EMULSION MUD (IOEM) Inverse oil emulsion mud is a “reverse” emulsion in which a refined mineral oil is the continuous phase with emulsified brine as the discontinuous phase. The diameter of the brine droplets is less than 1 micron. The oil continuous phase makes the system ideal for drilling claystone sequences and halites. The temperaure stability of the mud system is significantly higher than for most water based systems and it therefore has particular application for high temperature (greater than 300°F) and high pressure wells.

2.

COMPONENTS OF THE IOEM SYSTEM

2.1

The Oil Phase This is the main component of the system and is the continuous phase into which all other products are mixed. As the basis of the system, its characteristics exert a significant effect upon the properties of the mud. All the IOEM now run are of the low toxicity class. These are systems in which diesel oil has been replaced by a D.En approved low toxicity mineral oil. These oils are lower in aromatic and sulpher content than diesel. As a result, the “clean” oils have a lower chemical activity making it more difficult to obtain viscosity and emulsification properties than in a diesel system. In general, the lower the viscosity and aromatic content of the oil, the more difficult it is to build the mud initially. However, the low viscosity oils are desirable when high temperature, high mud weight systems are considered.

2.2

Brine Phase - Balanced Activity Many formations are capable of extracting water from IOEM by the process of osmosis. This can result in the formation hydrating and swelling much as if drilled with a water base mud. The absorption occurs because of a difference in chemical potential between the mud and the formation. In general, the more deeply buried the formation, the less water it contains and hence the greater the chemical potential. To offset this, the salinity of the water phase is increased to match the chemical potential of the formation. If the two are not balanced, then water will either be drawn into the formation if the mud salinity is low or from the formation into the mud if the salinity is too high. It is common practice to increase the salinity of the mud with depth to balance the increased chemical potential of the older shales. When defining the brine phase of the mud, it is either written as mg/l of chloride ion or as the activity of the mud.

2.3

Emulsifiers In general, oil muds contain a primary and a secondary emulsifier. The function of the primary emulsifier is to produce the emulsion, the secondary emulsifier provides for the oil wetting of the drill solids and barytes. Fatty acids, in particular, Tall oil fatty acids, are the most common primary emulsifier. When lime is added to the mud, the calcium soap is formed.

Note: This class of emulsifier will not function without lime. The secondary emulsifiers are generally of the polyamide type.

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Viscosifiers Emulsified water increases the mud viscosity, however, amine treated clays are the primary product for viscosity control. The most widely used clay is montmorillonite (bentonite) which is reacted with a quaternary ammonium salt to render it oil dispersible.

2.5

Factors Affecting the Performance of an Organophilic Clay The critical factor in the performance of an organophilic clay is its ability to swell properly. The largest part of the mud is the base oil which also has the most effect on the clay’s performance. The organic portion of the clay can be selected to aid solvation, but the general rule is, the more aromatic or napthemic an oil, the better the performance will be. The most difficult oils in which to produce solvation are those that are 100% paraffinic in nature. The water phase of an invert system greatly enhances the organophilic clay performance. This can easily be demonstrated by changing the oil/water ratio of a system. Moving from a true oil mud to an invert emulsion with an oil/water ratio of 70:30 the yield point obtained from a given concentration of organoclay can rise tenfold.

2.6

Application of an Organophilic Clay The main physical factors effecting the performance of the clay are: i) Shear. ii) Heat. iii) Method of addition. In the clean oils, it is difficult to obtain viscosity due to the lack of chemical reactivity of the oil. The maximum viscosity that the clay can impart can be achieved either through high shear such as through the bit or alternatively, heat will also have a similar effect. If adequate mixing facilities are available, the brine could be added directly to the dispersed clay in oil. The organoclay would act as an emulsifier to prevent its own settling and phase separation at the same time as it begins to develop a gel structure. Emulsifiers could then be added and although some structure will be lost, the rheology of the finished initial mix should be closer to that of a circulated mud.

2.7

Filtration Control Additives that are used for filtration control are asphalt, gilsonite and amine treated lignites. Asphalt is not used by BP as its use increases the toxicity of the mud system. Amine treated lignites are the preferred product.

2.8

Oil Wetting Agents Because most minerals carry a negative charge, cationic or positively charged molecules are used as oil wetting agents. Lecithin is one amongst many compounds that are used for this purpose. The hydrocarbon tail dissolves in the oil and the polar head in the water phase with the quaternary amine attaching itself to the mineral surface.

3.

PHYSICAL PROPERTIES OF IOEM/TYPICAL PARAMETERS

3.1

Oil/Water Ratio Oil/water ratio in the UKCS primarily to meet D.En criteria on discharged cuttings. Other reasons are: i)

The higher the oil/water ratio, the more expensive the system as not only is more oil required, but more viscosifier and fluid loss additive is required.

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With increasing mud weight it becomes increasingly difficult to maintain a stable emulsion and prevent water wetting with a high water content.

Oil/Water

Mud Weight (SG)

50/50 51/49 - 55/45 56/44 - 59/41 60/40 - 65/35 66/34 - 69/31 70/30 - 79/21 80/20 - 90/10

To 1.20 1.21 - 1.32 1.33 - 1.45 1.46 - 1.55 1.56 - 1.68 1.69 - 1.92 1.93 - 2.28

The exception to this rule is whilst drilling Zechstein Salt Formation. Even with a mud weight of 1.20 SG, it is advisable to run an oil/water of 75/25 - 80/20. This is to minimise the effects of salt water flows and water spotted to free stuck pipe. 3.2

Viscosity The funnel viscosity is of little relevance in IOEM due to the large variations with temperature. The PV, YP and Gels should as a standard be measured at 120°F. However, when the average circulating temperature is significantly different, the rheology should also be determined at the flowline temperature. Typical rheological properties are: 17 1/2”

PV 30 - 40 cP YP ± 25 lbs/100 sq.ft

12 1/4”

PV 30 - 40 cP YP 18 - 22 lbs/100 sq.ft

8 1/2”

PV 20 - 40 cP YP 15 - 20 lbs/100 sq.ft

Note: For guidelines on rheologies required for hole cleaning, see Section 4900. 3.3

Water Phase Salinity The chlorides should be reported as mg/L in the water phase not on the entire mud. In the majority of cases, calcium chloride will be used to make up the brine phase. Chloride content as a general rule is run between 150,000 - 170,000 mg/L.

Note: The maximum concentration with sodium chloride is approximately 180,000 mg/L. 3.4

HTHP Fluid Loss This is, as a standard, carried out at 500 psi. The temperature will depend on the formation temperature. However, the minimum should be 200°F as this test also gives a measure of the stability of the system. No water should appear in the filtrate as this is a sign of a weakening emulsion. If water does appear, it should be treated with emulsifier rather than a fluid loss additive. Lowering the fluid loss

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with amine treated lignite may remove water from the filtrate but this is only masking an inherent weakness in the emulsion. 3.5

Mud Weight Temperature should be reported with mud weight due to the changes that occur.

3.6

Electrical Stability This test is very operator dependant and should only be used as a guide. A steady decrease in voltage can be taken as an indication that an emulsifier treatment is required. A minimum voltage is usually taken as 500 volts. However, in 12 1/4” and 8 1/2” intervals values from 1000-2000 may be obtained. Conversely in 17 1/2” hole, values of only 300 volts may be obtained due to low shear and high dilution rates.

4.

POTENTIAL PROBLEMS WITH IOEM

4.1

Water Wetting When water wetting of the solids occurs, it will show itself in a number of ways: i)

The mud will have a “grainy appearance”.

ii)

Water breakout may occur in the filtrate.

iii) Electrical stability will drop. If the wetting becomes severe, then the drilled solids coming over the shakers will stick together. It may even be posible for the geologist to wash the cuttings samples in water rather than diesel. Barytes will also be removed over the mud cleaner screens. This situation can result from: i)

Fast drilling in the 17 1/2” interval.

ii)

Insufficient treatment with either emulsifiers and/or oil wetting agent.

iii) A rapid weight up. iv) A water flow. Under conditions i), iii) and iv) periodic treatments of oil wetting agent should be made. 4.2

Hole Cleaning See Section 4900.

4.3

Salt Drilling Whilst drilling long salt sections, the salt may “creep” resulting in stuck pipe. This is particularly true for IOEM which drills a near gauge hole. The most likely time for becoming stuck is whilst making a connection. The recommended practice for avoiding this is: 1. 2. 3.

Drill kelly off completely. Pull up with pumps on. Ream single down.

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If the string becomes stuck it is usually at the bit and can be freed by pumping/soaking a 20-30 bbl seawater pill containing 1 - 2% by volume drilling detergent. Another potential problem occurs whilst drilling the Zechstein Salt Formation which contains Magnesium salts. The Magnesium reacts with the lime in the mud system removing the excess concentration. If this is not replaced, then the primary emulsifiers of the fatty acid type will no longer function with potentially disastrous results. Providing an excess lime concentration is maintained this should not be a problem. The polyamide type emulsifiers are not affected by the Magnesium. Mud cleaners should be run whilst drilling any salt formation as the salt crystals have a high affinity for water and can extract water from the emulsion resulting in “water breakout” in the HTHP filtrate. 4.4

Water Flows This is a particular problem in high weight, high oil/water ratio systems. The influx of a small amount of water will result in a relatively large drop in the oil/water ratio with a rapid increase in viscosity and decrease in emulsion stability. Whilst drilling in the Zechstein Salt Formation in the Southern North Sea, high pressure Magnesium salt water flows can occur and although mud weights are low, the combined effect of Magnesium and water can have disastrous results. If the mud has not been properly pre-treated, it can, and has resulted in, the eventual “flipping” of the mud with barytes settlement and eventual packing off of the drill string. To avoid this, emulsifier and oil wetting treatments should be maintained at a high level and a minimum 2-3 ppb excess lime concentration carried. Excess emulsifier concentrations must be determined whilst drilling these sequences.

4.5

Pollution See environmental guidelines for drilling operations.

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SALT SATURATED MUD

USE OF SALT SATURATED MUD This system is used for drilling salt sections. It is a low solids non-dispersed system based on the seawater polymer system.

2.

TYPICAL PROPERTIES pH Chlorides

9.5 - 10.5 190,000 mg/L

To saturate freshwater requires: 0.888 bbl freshwater 109 lbs salt 3.

}

for one final bbl

SALT SATURATING AN EXISTING MUD When salt is added to an existing mud, flocculation with increased viscosity and fluid loss will occur. To reduce this, the saturation should, if possible, be carried out over three circulations.

3.1

1st Circulation Reduce funnel viscosity to 35/40 and MBT to 12-15 ppb.

3.2

2nd Circulation Add salt at ± 110 lb/bbl of aqueous phase. Correction for the solubility of salt with temperature can be made after the third circulation is satisfactorily completed.

3.3

3rd Circulation Adjust alkalinity, fluid loss and viscosity to the desired properties.

4.

RUNNING A SALT SATURATED MUD a)

The mud is normally run as a polymer system using XC polymer and starch for viscosity and fluid loss control respectively.

b)

In high salt concentrations, the effectiveness of FCL decreases. In these circumstances it may be better to use a low molecular weight polyacrylate dispersant. However, viscosity control in this system is not usually a problem whilst drilling salt but it may be if long shales sections have to be drilled in addition to the salt.

c)

Above 300°F, Hostadrill 2825 should be used for fluid loss control.

d)

If foaming is a problem, increasing the Pf to greater than 1.0 cc may reduce this.

e)

If there are indications of sticking whilst making a connection, this is most likely due to salt creep. Running a small stream of water at the suction will result in a slight washing out on bottom and may prevent the problem.

f)

With increasing temperature, the solubility of salt increases as below:

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SALT SATURATED MUD

Temp °F

NaCl ppb

122 158 212 302 356

104.8 106.3 111.7 120.7 128.4

Thus to prevent washouts under downhole conditions, the mud must be saturated with respect to the bottomhole temperature to be experienced. This will result in salt crystals forming under surface temperature conditions which may be removed by the solids control equipment. Thus it may appear that it is necessary to continually add salt downstream of the solids control equipment to maintain saturation under downhole conditions. However, when thick salt sections are drilled, the mud will pick up enough salt as drilled solids to ensure saturation in spite of losses of salt through the solids control equipment. If this situation is correctly analysed, the new volumes of mud can be added with less salt than would normally be required. The fluid must still be saturated at surface temperature, but excess may not be required.

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BARYTES PLUG - WATER BASED MUD

APPLICATION The use of Barytes plugs is limited to extreme or emergency conditions where it is imperative that some measures be taken to seal off the bottom section of a borehole. This type of plug is applicable in several types of situations, including:

1.1

1.

Simultaneous kicking and lost circulation.

2.

Abandonment procedure allowing safe withdrawal of drill pipe to allow setting of cement plug.

3.

Withdrawal of drill pipe to either set casing or repair existing casing strings.

4.

Plugging drill pipe in emergency situations.

Function Ideally, a successful Barytes plug should accomplish two things:

1.2

1.

Initially, the weight of the Barytes slurry should kill the well.

2.

After a period of time, the settled Barytes plug should mechanically block any flow up the wellbore. In reality, it is unlikely that the first objective can be achieved if a high pressure kick is experienced.

Design of Barytes Plug - Water Base Mud The following factors must be taken into account when designing a Barytes plug:

1.2.1

Slurry Weight The requirement of a Barytes plug is that the Barytes settles as rapidly as possible within the limits that it is possible to displace the slurry without plugging off the drill string. As the settlement rate is inversely proportional to the slurry weight, the slurry weight should be the minimum required. The range of slurry weight is generally 1.90 - 2.60 SG. Lighter weight slurries, in the range of 1.70 - 1.90 SG, are suggested for setting plugs inside casing or drill strings where filtration does not occur and rapid settling is desirable. Higher weight slurries are suggested for the open hole where both settling and high filtration aid in making an immovable seal.

1.2.2

Slurry Volume The effective settled/compacted height of the Barytes is less than that of the slurry as pumped. This should be taken into account when determining the volume required. As a guideline, tests on a 2.40 SG slurry indicate that the settled height is approximately 70% of the original height. In general, a settled plug height of 50 - 150m is sufficient.

1.2.3

Slurry Viscosity The higher the viscosity of the slurry, the lower the settlement rate will be. A high settlement rate is obviously desirable from the stand point of blocking off flow from the well. In addition, the higher the settlement rate, the harder the settled pack of Barytes is. Settlement rates for high weight slurries are normally too low and require a dispersant to increase the rate. The required dosage will depend on: i) Dispersant type. ii) Slurry weight. iii) Barytes quality. Any dispersant such as Lignosulphonate, SAPP or Polyacrylate can be used. However, because of variation in Barytes quality, it is essential that a pilot test is carried out. As a result of variation in

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BARYTES PLUG - WATER BASED MUD

Barytes quality and dispersant used, it is not possible to give dispersant concentrations required. However, laboratory tests and a field trial indicate that slurry should have the following approximate rheology at ± 60°F. Yield point -5 to -8. The mix should be made in drill water in which the pH has been adjusted to 9.5 - 10.5 with caustic. Barytes and drill water requirements are listed below for various slurry weights.

1.3

Slurry Weight SG

Drill Water gal/bbl

Barytes lbs/bbl

1.70 1.90 2.10 2.40 2.65

33.0 29.8 26.7 23.6 20.4

313.5 424.0 534.6 645.2 755.8

Mixing Procedure The slurry can be mixed in either a well agitated slug pit or using the cementing unit. If the slug pit is used, particular attention will be required to ensure that Barytes does not settle out whilst mixing. Mixing may require two centrifugal pumps as the slurry weight increases towards 2.40 SG. If the cementing unit is used, the liquid phase should be mixed in the mud pits and then transferred to the cementing unit for weighting up.

1.4

Displacement Procedure Displacement techniques are the same as in cementing, i.e. the slurry should be underdisplaced. When calculating the volumes for the displacement, adjust so that the height of the slurry will be 2 barrels greater inside the drill pipe. This allows the drill pipe to be withdrawn with a natural slug. It will also minimise movement of the slurry in the hole which causes contamination. Because of the high density of these slurries, high differential pressure can be created by excessive underdisplacement or overdisplacement. So care must be taken while calculating the displacement volumes. After spotting the plug, the drill string must be withdrawn immediately from the plug to prevent sticking due to Barytes settlement. Circulate clean on top of the plug. A displacement rate of 5-8 bbl/min is recommended. If possible, the plug should be displaced either open ended or through a bit containing no nozzles. In a field trial, however a 2.40 SG plug was displaced through a bit containing 3 x 13 nozzles with an increase in pressure of 200 - 400 psi observed as the plug exited the bit. The plug should not be displaced through a bit containing nozzles unless the string contains a circulating sub or unless the drilling office is first consulted.

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BARYTES PLUG - OIL BASED MUD

DESIGN OF BARYTES PLUG - OIL BASED MUD The application, function and design of Oil Barytes Plugs with respect to weight volume and viscosity is identical to those for water based plugs. The basic design consists of base oil, Barytes and an oil wetting agent. However, due to the very different nature of oil wetting agents used by the various mud companies, it is more difficult to define standard formulations than for water base. Individual formulations will therefore be suppled for each mud company. The oil and Barytes requirements are listed below for various slurry weights.

Slurry Weight SG

Base Oil gal/bbl

Barytes lbs/bbl

1.70 1.90 2.10 2.40 2.65

31.1 28.1 25.1 22.1 19.2

381.8 485.9 589.9 693.9 797.9

Note: The requirements are calculated assuming a base oil SG of 0.8. For a different SG, the requirements will have to be recalculated. 1.1

Mixing and Displacement Procedure These are as described in Barytes Plug - Water Based Mud.

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LOST CIRCULATION

CAUSES OF LOST CIRCULATION Mud loss or circulation loss is the loss of mud or cement to the formation during drilling operations. Losses can result from either natural or self induced causes.

1.1

Natural Losses Three types of formation can be identified into which losses can occur. a)

Coarse Sands and Gravel Beds Formation openings into which mud is lost must be about three times larger than the particle size found in the mud. Thus a formation must typically have a permeability in excess of 10 - 25 Darcys for mud to be lost. Therefore, this type of loss is practically confined to gravels and coarse sands near surface.

b)

Natural Fissures of Fractures These can be very permeable under normal conditions and are the source of production in some fields. In BPX’s world-wide operations, they are the main cause of lost circulation. Losses can occur at very low overbalance pressure.

c)

Cavernous Formations Caverns are normally found in limestone and dolomite.

1.2

Induced Fractures In formations where the difference between pore pressure and fracture pressure is low, losses may occur to formation facture caused by drilling ECD or surge/swab pressures.

1.3

Excessive Overbalance Excessive overbalance may in some instances not fracture but losses through the pores may occur.

2.

PREVENTION OF LOST CIRCULATION For all drilling operations, lost circulation prevention procedures should be considered. Listed below are potential causes and measures which can be taken to prevent losses occurring.

2.1

Increase in annular mud weight due to drilled cuttings can result in formation breakdown, particularly in surface holes. The effective increase in annular mud weight must be calculated and taken into account. Example ROP Circulation Rate Hole Size Input Mud Weight Formation Density

30 metres/hour 1200 gpm 17 1/2 inches 1.08 sg 2.30 sg

Resultant mud weight (MW) = 1.10 sg 2.2

Viscosity and gel strengths of the mud should be maintained within the programme specification. If the yield point is too high, breaking circulation may induce losses. On breaking circulation, always start circulation slowly and speed up the pump only after returns are obtained. If viscosities are very high, circulation should be broken at stages whilst running through the open hole.

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High viscosity can increase the ECD to a level which will break down the formation whilst circulating. When calculating ECD values in critical situations, account should be taken of the OD of pipe connections. The effect of drill pipe rubbers should also be considered in such situations. 2.3

Excessive surge pressure whilst running in the pipe can fracture the formation. In areas of potential lost circulation, surge pressure calculations should be performed and the driller instructed as to the maximum allowable speed for running pipe.

Note: Surge pressure is placed on the formation the moment the string is run in the hole. In areas of potential lost circulation, tripping speeds must be controlled all the way to/from surface. 2.4

In areas of hole instability sloughing or swelling shales can pack off around the pipe reducing or preventing circulation. If the pump is not slowed or stopped at this point, the formation can be broken down. The driller should be made aware of areas of potential hole instability.

3.

REPORTING OF LOST CIRCULATION When reporting instances of lost circulation, the following is to be included: 1.

Static Loss Rate

bbl/hr.

2.

Dynamic Loss Rate

bbl/hr @ gpm.

3.

Depth.

4.

Note if the losses build to the loss rate gradually or suddenly. This is helpful for distinguishing losses through pores which require only fine LCM and losses into fractures which can require coarser grades.

3.1

Determination of the Source of Lost Circulation

3.2

Non Formation Losses When lost circulation occurs the following procedure should be followed: 1.

Establish loss rate.

2.

Check all surface equipment to ensure no losses.

3.

Check with mud logger/mud engineer that no mud has been dumped/transferred or no solids control equipment has been switched on.

4.

Check that the riser slip joint packing is not leaking.

Other non formation possibilities are:

3.3

1.

Leaking casing. A packer should be run to determine the loss depth in this instance.

2.

Riser leaks.

Formation Losses If losses are experienced whilst drilling, it is likely that the losses are on bottom. If losses are experienced whilst tripping or whilst increasing mud weight, it is likely that the loss zone is not on bottom. Methods for establishing the loss zone are:

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a)

Temperature Survey. Normally requires two runs. However, a variation of the technique can be used by stopping the sonde at a certain depth and pumping for a short period. This will give a temperature change. The instrument is lowered to successive levels in the hole until no temperature change is recorded (i.e. no flow to formation past this point).

b)

Spinner Survey. Flowrate is indicated on film according to the speed of a varied rotor on the instrument.

c)

Tracer Survey. Using a gamma ray log and radioactive material. Conventional. Run a base log through the drill pipe. Then pump a slug of mud with radioactive material down the drill pipe and repeat the log. Where the sonde encounters a high radioactivity it indicates the loss point. Variation. If point of loss is suspected near last casing shoe, a small quantity of radioactive iodine can be pumped down the annulus. The sonde is run inside the drill pipe, following the tracer, while it is being pumped. The loss point has been reached when radioactive contact is lost.

4.

PROCEDURES FOR CURING LOST CIRCULATION

4.1

Reducing Mud Weight When lost circulation is experienced, if possible, the mud weight should be reduced. An estimate of the maximum mud weight the formation can stand can be obtained by the method described below. 1.

If there are returns, fill the annulus with a measured volume of water or base oil, depending upon mud system, and calculate the new gradient.

2.

If there are no returns when pumping: a)

Same as “1”.

b)

Compare the circulating pressure prior to the losses occurring (Pressure A) with the pressure at the same circulating rate after the losses have occured (Pressure B). Pressure A - Pressure B Mud Weight psi/metre

=

height of empty hole

If the position of the loss zone is known a new mud gradient can be calculated to balance the weak formation. Reduction of the ECD may be ncessary in some instances. 4.2

Use of Lost Circulation Material There are many types of lost circulation material available which have applications according to the type of losses experienced. Typical materials used are: Conventional LCM Flake

Mica Cellophane

Granular

Nutshells Calcium Carbonate Salt

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Fibrous

Glass Fibre Wood Fibre Animal Fibre

Note: In oil based muds, the listed fibrous materials cannot be used as the materials can severely weaken the emulsion stability. “Ven-Fyber”, a cellulosic fibre treated to render it oil wettable is used. High Fluid Loss Slurry Diaseal M Seelit Sureseal Reinforcing Plugs and Cement Oil/bentonite plug (water based muds). Water/organophilic clay plug (oil based muds). As stated, the choice of pill depends on the type of lost circulation experienced. In general, the reinforcing plugs and cement formulations are considered to be specialised formulations for severe lost circulation circumstances and should not be used as a matter of routine. 5.

LCM FORMULATIONS AND SPOTTING PROCEDURES (NON-RESERVOIR) For each of the following circumstances, two alternative LCM formulations are given. Each is considered to be acceptable.

Notes: a) It is considered that LCM concentrations in excess of 30 to 45 ppb are unlikely to have increased benefit. b) When considering concentrations, the density of the LCM must be considered. For example, liquid casing and OM Seal have densities of 1.1 sg compared to 2.7 sg for calcium carbonate. Thus higher concentrations of the more dense material are required to obtain the same volume of LCM. 5.1

Seepage Losses (Losses less than 10 bbl/hour) Option 1 Add mica fine to the circulating system at 4 to 5 x 25 kg per hour for several hours. Option 2 Add liquid casing to the circulating system at 4 to 5 x 25 lbs per hour for several hours. Loss Rate (10 - 20 bbl/hour) Option 1 Mica fine Mica medium

+/- 15 ppb +/- 15 ppb

Option 2 Liquid casing

15 ppb

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Loss Rate (Greater than 20 bbl/hour) Option 1 Mica fine Mica medium Kwikseal medium

15 ppb 15 ppb 15 ppb

or for OBM Venfyber at 8 ppb instead of Kwikseal.

Note: Kwikseal medium can result in excessive filter cable build-up. Care must therefore be exercised when tripping past the lost circulation zone. Option 2 Liquid casing OM Seal Marble (5 micron median)


Note If these formulations are unsuccessful, an alternative formulation is: Liquid casing or mica fine Kwikseal coarse

15 ppb 25 ppb

For OBM, replace Kwikseal coarse by Venfyber at 15 ppb. Kwikseal coarse may result in nozzle plugging. 5.3

5.4

Precautions a)

When an MWD tool is the drill string, coarse grade LCM should not be pumped. For materials such as Kwikseal and Venfyber, recommendations of the MWD supplier should be sought.

b)

Liquid casing and OM seal should not be used above 250°F.

c)

The pill should be displaced at approximately 200 gpm.

d)

When lost circulation is expected the minimum nozzle size should be 16/32nd. If smaller sizes are required, a circulating sub should be incorporated into the string.

e)

A rule of “thumb” for successful bridging is that the LCM will block an opening three times its diameter. Whilst this may apply for grannular materials, it is doubtful if it applies to fibrous materials. For these materials, the figure may be in excess of 5 times its size.

High Fluid Loss Slurry These slurries are good for induced fractures where bridging is not paramount but a high pressure drop along the fracture is. Mud solids should provide the fines to bridge with this material. Slurry formulations for 1 finished bbl are given below:

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Slurry Density SG

Diatomaceous Earth lbs

Barytes lbs

Seawater bbl

1.08 1.20 1.30 1.45 1.55 1.70 1.80

50.0 42.6 38.9 35.8 32.7 29.3 26.5

0 60.0 120.0 180.0 230.0 290.0 350.0

0.93 0.90 0.86 0.83 0.80 0.76 0.73

1.

A slurry volume of 50-100 bbl is used.

2.

Pull off bottom to just above the loss zone.

3.

Displace slurry with mud out of the drill string.

4.

If returns are obtained and the hole is full, close the annular preventer and squeeze with a maximum of 500 psi squeeze pressure. The hesitation technique is preferred. If all the slurry is squeezed to the formation, hold pressure for 30 minutes.

5.

If no returns are obtained and the hole cannot be filled after displacing the slurry out of the drill string a second LCM slurry should be pumped.

Note When Using High Fluid Loss Slurry 1.

In zones of low porosity but containing fractures, the slurry will only filter once the fracture width reaches that of the maximum particle size in the slurry. Therefore, there is a need to add additional bridging LCM. A concentration of 10 ppb of fibrous LCM is usually added such as Kwikseal fine. Nothing coarser should be used or it may prevent the ingress of the DE.

2.

Hydrostatic pressure is often enough to seal the loss zone. A squeeze pressure is applied, however to open up and then seal fractures which would otherwise cause problems later.

3.

The basic slurry or slurry containing low concentrations of fibre can be pumped through bit jets.

4.

In oil base muds, the same procedure with some modifications can be used. a)

The mixing pit and mixing lines should be cleaned and washed with water.

b)

Formulate the slurry as previously described.

c)

Pump a 20 bbl oil spacer in front of the slurry and balance behind.

d)

The displacement and squeeze procedure is as previously.

Extreme caution should be exercised during the surface mixing of the slurry to prevent contamination of the mud. 6.

LCM FORMULATIONS (RESERVOIR SECTIONS) If losses occur in the reservoir interval, the first step should be to reduce the mud weight. If this is not possible and after prior approval from the onshore drilling superintendent, the following LCM’s can be used. However, specific permission of the relevant field or exploration groups may be required.

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Option 1 (Liquid Casing) Loss rate < 20 bbl/hour:

Liquid Casing

15 ppb

Loss rate > 20 bbl/hour:

Liquid Casing OM Seal Marble (5 micron)


Notes: 1) This LCM system should not be used with temperature above 250°F. 2) Liquid casing/OM seal are only 40% soluble in HCl. They are however almost totally soluble in 2% hypochlorite solution. 3) Although this material is only partially acid soluble, it has been approved for reservoir applications. This is due to the fact that the material is very easily back-flowed. Option 2 (Marble) Seepage (Less than 10 bbl/hour) Add (50 micron median size) to the circulating system at 4/5 x 25 kg sacks per hour for several hours. Loss Rate 10 - 20 bbl/hour 50 micron median size 150 micron median size

15 ppb 15 ppb

Loss Rate 20 - 40 bbl/hour 50 micron median size 150 micron median size 600 micron median size


Notes: 1) Nozzle size must be 3 times larger than the largest particle size to be pumped. 2) The material is acid (HCl) soluble. 3) Marble is preferred to the normal calcium carbonate. This is because the material retains its grind size unlike calcium carbonate which is easily ground down. 7.

SPECIALISED FORMULATIONS As discussed in Section 4.2, there are specialised formulations for severe cases of lost circulation. These are discussed below:

7.1

Oil/Bentonite Plug The plug uses the fact that bentonite will not hydrate in oil but when water contacts the oil/bentonite mixture, a solid strong material is formed. In seawater based muds, a fresh water spacer is pumped in front of and behind oil spacers to promote the hydration of the bentonite which would be poor in a saline environment. Procedure (Displacement) 1.

The slurry is preferably pumped through open ended pipe. It can however, be pumped through nozzles if it is not possible to trip out of the hole.

2.

Flush cement unit, slug pit and all surface lines with base oil - either base oil or diesel.

3.

Mix 300 ppb bentonite into the base oil: a viscous slurry will result.

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4.

Pump 30 bbl of fresh water.

5.

Pump 10 bbl of base oil.

6.

Pump the plug.

7.


8.

Pump 30 bbl of fresh water.

9.

Displace the plug to the bottom of the drill string.

Squeeze Operation 1.

If the hole is full, close the annular and squeeze at 300 - 500 psi into the formation.

2.

If the hole is not full, close the annular and pump at the same rate down the annulus and drill pipe.

3.

Allow four hours for the plug to set.

Note: A cement squeeze can be used on top of the base oil/bentonite plug, the latter providing a backing for the cement to prevent its loss into the formation. 7.2

Base Oil/Bentonite/Cement If the base oil/bentonite plug does not work, a base oil/bentonite/cement plug is recommended. A concentration of 300 - 500 lbs of bentonite and cement in a 1:1 mixture is mixed into the base oil. The displacement and squeeze procedure is as for the oil/bentonite plug.

7.3

Water/Organophilic Clay Plug In oil based muds, the reverse of an oil/bentonite plug is used, the water/organophilic clay plug. In oil muds, a clay which has been chemically treated to render it oil dispersable is used to provide viscosity. This organophilic clay will not yield in water but will yield in oil in the presence of water. Thus if a high concentration of clay dispersed in water is pumped to the loss zone, on contact with oil mud, it will form a strong solid material. Formulation (for 1 bbl mix) Unweighted Water Caustic Dispersant Organophilic Clay

0.72 bbl 1.5 lbs 3.5 lbs 250.0 lbs

Mixing/Displacement Procedure 1.

The slurry is preferably pumped through open ended pipe. It can, however, be pumped through nozzles if it is not possible to trip out of the hole.

2.

Flush cement unit, slug pit and all surfce lines with a water rig wash mixture to clean the lines. When the lines are deemed to be clean, flush again with water.

3.

Mix the slurry as previously outlined.

4.


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5.

Pump 10 bbl of water.

6.

Pump the slurry.

7.

Pump 10 bbl of water.

8.


9.

Displace the plug to the bottom of the drill string.

Note: The function of the base oil spacer is to separate the oil mud and water to prevent gelling in the drill string. Squeeze Operation The squeeze operation is carried out as per the procedures outlined for the oil/bentonite plug.

Note: Cement cannot be used in water organophilic clay plug. 8.

LOST CIRCULATION WHILST DIVERTER DRILLING For drilling top hole sections (26”) where it is believed that mud will help to stabilise the hole the use of the riser/diverter may be programmed. If losses occur in this situation which cannot be cured by reducing the ROP, it is likely that the only effective course of action to take will be to pull the riser and to drill the section with seawater and viscous pills in the usual way.

8.1

Internal Blowout Excessive wellbore pressure, with a closed-in well after a “kick”, can cause a formation breakdown and an internal blow-out. This type of lost circulation is difficult to cure. Prepare heavy mud if possible 3 times the volume of drill pipe contents and open hole volume from bottom to the casing shoe. Also prepare 100 bbls pills with a high concentration of LCM to be pumped down the annulus with light weight mud that the hole could stand before the kick. Pump heavy mud down the drill pipe and up the annulus to the shoe (or point of losses) and simultaneously pump the 100 bbls of LCM pill down the annulus. Calculate the time and pump speeds in annulus and drill pipe in such a manner that both columns arrive at the point of loss at the same time. Fast pumping of the heavy mud and if necessary of the light weight mud initially, whilst slowing down to half speed or less as the plugging material is allowed time to seal off the formation. Note that the pressure of the column should be in balance or slightly over balanced to kill the well.

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CONTAMINATION OF DRILLING FLUIDS

CONTAMINATION OF DRILLING FLUIDS (Water Based Muds) Contamination of the mud is a steady process while drilling, as drilled solids are continually entering the mud. While much of the drilled solids are inert, there are certain materials which can cause severe chemical and physical problems. Contaminants will tend to become apparent more quickly with lightly treated muds such as gel/polymer muds rather than with highly treated gyp-lignosulphonate muds. Any contamination should be treated immediately, so careful and frequent checks should be kept on the actual mud properties. Advance treatment to prevent contaminants affecting the mud can be made if, for example, a complete geological prognosis is available or when drilling out cement. Whenever the mud has been contaminated and a cure is required, careful pilot testing should be carried ou;t before treating the complete mud system.

2.

CARBONATE/BICARBONATE Carbonate and bicarbonate are probably one of the more unrecognised contaminants. It is usually a gradual contamination resulting in increased gel strengths and yield point. This can be incorrectly diagnosed as increased solids resulting in costly treatments. Prior to discussing contamination by these ions, it is important to understand the concept of alkalinity. When a pH measurement is made, the value obtained can be due to a variety of ions, such as hydroxide, carbonate bicarbonate and even anionic polymers such as CMC and lignosulphonate. Thus a pH measurement is insufficient to define the alkalinity of the system. Pf and Mf measurements must also be made. A pH of 9.5 may be obtained which could be thought to be adequate. However, this could be derived from a mixture of carbonate and bicarbonate with no hydroxide alkalinity. Since lignosulphonate requires hydroxide to function, this could present severe problems. The effect of alkalinity type and its effect on mud rheology is presented below: a)

Hydroxide only

-

Mud stable and in good condition.

b)

Hydroxide & Carbonate

-

Mud stable and in good condition.

c)

Carbonate & Bicarbonate -

Stable but difficult to control.

d)

Bicarbonate only

Unstable and very difficult to control.

-

Carbonates can be derived from: a)

CO2 from drilled formations.

b)

Thermal degradation of organic additives.

c)

Overtreatment with soda ash or bicarbonate of soda.

d)

Carbonate formations.

When CO2 enters water, it forms carbonic acid. With increased pH, it forms bicarbonate and with a further increase it converts to carbonate. It must be stressed that these are equilibrium reactions and that carbonate and bicarbonate can co-exist at certain pH. H2 CO3

+

–

H HCO 3

+

2H

2–

+ CO 3

Generally, CO2 dominates below pH 6.3 and bicarbonate in the range 6.3 - 9.4 with carbonate predominating above 9.4.

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2.1

Carbonate Detection Methods

2.1.1

Pf/Mf This relies on the ratio of Pf/Mf and the general rule is: Pf Pf 2Pf 2Pf 2Pf

= = = => <=

O Mf Mf Mf Mf

Alkalinity due to bicarbonate only. Alkalinity due to hydroxide only. Alkalinity due to carbonate only. Alkalinity due to carbonate and hydroxide. Alkalinity due to carbonate and bicarbonate.

then Carbonate concentrationif hydroxide present is: [Mf - Pf] x 1200 ppm Carbonate concentrationn if hydroxide absent is: Pf x 1200 ppm Bicarbonate concentrate [Mf - 2Pf] x 1220 ppm Hydroxide concentration [2Pf - Mf] x 340 ppm This is a very unreliable method as it takes no account of alkalinities other than carbonate/bicarbonate and hydroxide. The Mf measurement is also very difficult, particularly in lignosulphonate treated muds. 2.1.2

P1/P2 Procedure: To 1cc filtrate add 24cc water. Titrate to pH 11.4 with 0.1M NaOH. Add 2cc of 10% Barium carbonate. Titrate to phenolphthalein end point with 0.02N H2SO4. The volume of 0.02N H2 SO4 = P1 Repeat above procedure using 25cc distilled water with no filtrate. The volume of 0.02N H2 SO4 = P2 If P2 > P1 If P1 > P2

No Hydroxide present No Bicarbonate present

Calculation If P2 > P1 [Bicarbonate]

=

1220 (P2 - P1) ppm

[Carbonate]

=

1200 x Pf ppm

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If P1 > P2 [Hydroxide]

=

340 (P1 - P2) ppm

[Carbonate]

=

1200 [Pf - (P1 - P2)] ppm

This method gives more accurate results than the Pf/Mf method, however it is difficult to obtain reproducible results. This is thought to be due to localised regions of low pH due to rapid titration resulting in barium carbonate going into solution and giving off CO2. 2.1.3

Garrett Gas Train This is the most accurate method, however it gives carbonates/bicarbonates in terms of total carbonates. A level of 300 - 500 ppm is considered background in this test. Levels of 600 - 800 ppm could cause problems with levels in excess of 1000 ppm causing severe problems.

2.1.4

Treatment If carbonates are suspected, maintaining a pH in excess of 10.0 will ensure that very little bicarbonate exists. a)

Increase pH to 9.5 - 10.0 with caustic.

b)

Add lime at 0.043 ppb per 100 ppm carbonate.

c)

If the required treatment for lime exceeds 0.5 ppb, treat with gypsum. 0.1 ppb gypsum will treat 100 ppm carbonate. Whilst treating with gypsum, caustic additions will be required to maintain pH.

Notes: a)

When adding lime or gypsum, the mud will become very viscous if large treatments are made. TREATMENTS ARE BEST MADE THROUGH A CHEMICAL BARREL AND SHOULD NOT EXCEED 0.5 PPB OVER A 6 HOUR TREATMENT PERIOD.

b)

In the mud manuals, various concentration terms may be used such as EPM. To convert to ppm, the procedure is: PPM = EPM x Eq Wt Where EPM = Equivalent parts per million. Table I Equivalent Weights of Various Compounds Compound

Eq Wt

Carbonate Bicarbonate Hydroxide

30 61 17

Concentration of bicarbonate as low as 250 ppm can cause problems.

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In areas where carbonate contamination is known to be a problem, the pH should be maintained with caustic and lime in the ratio 2 cans caustic to 1sk lime.

CEMENT This is contamination from calcium hydroxide which can result in severe thickening and increased fluid loss. The severity of the problem will depend on the level of pre-treatment and thinner concentration in the mud. In a highly treated Lignite/Lignosulphonate system, the viscosity may actually dro as the clays go to an aggregated/de-flocculated state rather than a dispersed/flocculated state on the introduction of cement.

3.1

Cement Contamination Recognition When cement is introduced into a mud, chemical tests should reveal the following: a) b) c)

3.2

An increased pH. Increase in Pf and calcium. A large increase in PM.

Treatment for Cement Contamination a)

Prior to drilling out a shoetrack, pre-treat the mud with 2 - 4 sx of sodium bicarbonate.

b)

Treat cement contamination at the rate of: 0.15 ppb sodium bicarbonate/100 ppm calcium.

Note: If sodium bicarbonate treatment levels are based on filtrate calcium only, an incorrect treatment level will be obtained. This is because the majority of the cement will stay in suspension rather than go into solution due to the high pH. To obtain the total calcium level, the following procedure should be adopted: i)

To 10 cm3 mud, add 90 cm3 distilled water.

ii)

Titrate with 0.1 N H2 SO4 to a pH of 7.5 - 8.0.

iii) Continue mixing for 2 mins to ensure no pH rise. iv) Filter the slurry on the standard filter press. v)

Titrate 10 cm3 of filtrate with standard versenate. Calcium = Titre x 400.

c)

When large quantities of cement are drilled, it may not be practical to treat out the contamination due to the large concentrations of bicarbonate required. In this case, additions of caustic and lignosulphonate should be made and the mud converted to a low-lime system.

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SALT CONTAMINATION If salt enters the mud, gellation and increased fluid loss will occur.

4.1

Salt Contamination Recognition a) b) c)

Increase in chlorides. Decrease in pH. Decrease in pf.

There is no effective treatment except to convert to a salt saturated system. 5.

CALCIUM SULPHATE This occurs whilst drilling anhydrite (CaSO4) and will result in flocculation with an increase in yield point, gel strengths and fluid loss.

5.1

Gypsum Recognition a) b) c)

5.2

Increase in filtrate calcium. Decrease in pH. Decrease in pf.

Treatment The contaminant should be treated with sodium carbonate at the rate of: Soda Ash 0.09 ppb/100 ppm calcium This treatment should be combined with chrome-free lignosulphonate.

Note: a) If large amounts of soda ash are added, the soluble sulphate may cause "ash gels" which are high progressive gel strength. b) If large amounts of anhydrite are to be drilled, it is best to convert to a gyp mud. 6.

HARDNESS Hardness in water is due to calcium and magnesium ions. Increasing the pH to 10.5 will precipitate out magnesium as magnesium hydroxide. Calcium should then be treated with soda ash at 0.09 ppb/100 ppm calcium.

7.

HYDROGEN SULPHIDE A detailed discussion on hydrogen sulphide contamination can be found in BPX HS&E Regulations.

SUBJECT:

TABLE II - CHEMICAL TREATMENT OF CONTAMINANTS

Sapp or

.000971 lb/bbl/ppm

Sodium Bicarbonate

.00147 lb/bbl/ppm

Calcium (Ca++)

Sodium Bicarbonate

.00147 lb/bbl/ppm

Lime (Ca++)

Sapp or

.0000535 lb/bbl/ppm

Sodium Bicarbonate

.000397 lb/bbl/ppm

Magnesium (Mg++)

Caustic Soda to pH 10.5 then add Soda Ash

.00116 lb/bbl/ppm

Calcium (Ca++)

Soda Ash

.000928 lb/bbl/ppm

Hydrogen Sulphide

Sulphide (S=)

Keep pH above 10 and add Zinc Basic Carbonate

.00123 lb/bbl/ppm

Carbon Dioxide

Carbonate (CO 3)

Gyp if pH okay

.00100 lb/bbl/ppm

Lime if pH too low

.000432 lb/bbl/ppm

Lime

.000424 lb/bbl/ppm

Cement

Lime

Hard Water

Calcium (Ca++)

–

–

Bicarbonate (HCO 3)

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:

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Section

.000971 lb/bbl/ppm

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Sapp if pH too high

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:

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Rev.

Calcium (Ca++)

6 of 6

Gypsum or Anhydrite

:

To Remove Add

Page

Contaminating Ion

DRILLING MANUAL

Contaminant

Amount to Add (in lbs/bbl) if Treating Agent to Remove 1 ppm Contaminant


Quantity of Treating Agent in lb/bbl Needed for Each ppm of Contaminant

BP EXPLORATION


MUD TESTING

1.

Density.

2.

Funnel Viscosity.

3.

Rheology.

4.

Filtration

5.

Sand Content.

6.

Solids Content - Retort.

7.

Alkalinity.

8.

Carbonate Determination in Water Based by the Garrett Gas Train.

9.

Cation Exchange Capacity.

10.

Chlorides Analysis.

11.

Total Hardness.

12.

KCL Content.

13.

Excess Polyacrylamide Content of Mud.

14.

Calcium Sulphate.

15.

Lime Content of OBM.

16.

Electrical Stability.

17.

Garrett Gas Train Analysis of Sulphides in Water Based Mud.

18.

Garrett Gas Train Analysis of Sulphides in Oil Based Mud.

19.

Field Procedure for Zinc Carbonate in Water Based Mud.

20.

Oil Content of Cuttings Discharge at the Shale Shaker.

-

Low Pressure Test. High Pressure Test.

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1.

DENSITY DETERMINATION

1.1

Procedure (Using Standard Mud Balance)

1.2

Section

a)

The instrument base should be set up approximately level.

b)

Fill the clean, dry cup with mud to be tested and tap the cup gently to allow entrapped air bubbles to escape.

c)

Replace the lid and rotate down until firmly seated, thus expelling excess mud through the vent hole. Always ensure that some of the mud is expelled otherwise insufficient quantity has been placed in the cup initially.

d)

Cover the vent hole with a finger and wash or wipe all the mud from the outside of the cup.

e)

Place the beam on the support and balance it by moving the rider along the graduated scale. The beam is horizontal when the bubble in thelevel glass is on the centre line.

f)

Read the density at the side of the rider towards the cup.

g)

Report the result as mud weight to the nearest 0.01 SG.

h)

Wash the mud from the cup immediately after use. It is absolutely essential that all parts of the mud balance are kept clean if accurate results are to be obtained.

Calibration The instruments should be calibrated every day with fresh water. Fresh water should give a reading of 8.33 ppg/1.00 SG.

Note: Care must be taken to ensure that the mud sample contains no entrained air. If the mud has a high gel strength, the Halliburton pressurised mud balance should be used. 2.

MARSH FUNNEL VISCOSITY Procedure a)

Check that the orifice of the funnel is free from any obstruction.

b)

Cover the orifice with a finger, and keeping the funnel in an upright position, pour the mud sample through the screen into the clean, dry funnel until the fluid level reaches the bottom of the screen.

c)

Immediately remove the finger from the outlet, at the same time starting a stop watch and measure the time required for the fluid to fill the receiving jug to the 1qt mark.

d)

Report to the nearest second the Marsh Funnel Viscosity and also the temperature of the sample in degrees Fahrenheit.

Note: Dependable results may be obtained by taking the sample at the flowline and running the test immediately. 2.1

Calibration To calibrate the Marsh Funnel, fill the funnel to the bottom of the screen with fresh water at a temperature of 70°F ± 5°F and note the time taken for the water to drain into the receiving jug to the 1qt mark. The time should be 26 seconds ± 0.5 seconds.

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RHEOLOGICAL PROPERTIES OF DRILLING FLUIDS Fann Viscometer - Model 35 Procedure for Apparent Viscosity, Plastic Viscosity and Yield Point a)

Place sample of freshly agitated mud into the viscometer cup to the scribed line. The rotor sleeve is immersed to the scribed line.

b)

With the sleeve rotating at 600 rpm, wait for the dial reading to become constant. Record the reading.

c)

Shift to 300 rpm, and wait for the dial reading to become constant. Record the reading. Plastic Viscosity

= 600 rpm (reading) - 300 rpm (reading) cP

Yield Point

= 300 rpm (reading) - PV lbs/100 ft 22

Apparent Viscosity = 600 rpm (reading) cP 2 3.1

Procedure for Gel Strengths Set the viscometer at high speed for ten seconds. Allow the mud to stand for ten seconds, then obtain the maximum 3 rpm reading. Re-stir at high speed for ten seconds. Allow to stand for ten minutes. Obtain the maximum 3 rpm reading [units lbs/100 ft2]. Note:

Shear Rate (sec-1)

=

rpm x 1.70

Shear Stress (dynes cm-2)

=

Dial reading x 5.11

Viscosity (Poise)

=

Shear Stress Shear Rate

(dynes cm-2) (sec-1)

Note: The rheology of oil based muds should be determined at 120°F. 4.

FILTRATION

4.1

Ambient Temperature/100 psi Test Procedure (Using Baroid Filter Press) a)

Before assembly, check that the centre orifice in the base cap is not plugged, the screen is clean and dry and that the rubber gaskets are not distorted, worn or cut.

b)

Assembly should be carried out in the following order:Base cap, rubber gasket, wire screen, a sheet of filter paper (Whatman No. 50, 9cm diameter), rubber gasket, cell body. Lock the cell body onto the base by turning clockwise.

c)

Fill the cell with freshly agitated drilling fluid to within 1/4” of the top, and place the unit in the filter press frame.

d)

Check that the rubber gasket is fitted to the top cap, place this cap on top of the cell and secure the unit in place with the “T” screw until hand tight.

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e)

Place a clean dry 10 ml or 25 ml measuring cyclinder under the mud cell orifice to receive the filtrate.

f)

Close the relief valve, open the gas inlet valve and apply a pressure of 100 ± 5 psi (kept permanently* regulated at gas source). Ensure that the pressure is constant and there are no leaks in the system. Collect all the filtrate (including the initial spurt loss) for a thirty minute period. * If the regulator is adjusted always, its diaphram is likely to be damaged.

4.2

g)

At the end of thirty minutes, close the gas inlet valve and bleed the cell pressure to zero by opening the relief valve slowly.

h)

Report the volume of filtrate in millilitres (to 0.1 ml) as the API filtrate loss.

i)

Remove the mud cell from the filter press frame. Disassemble the cell, discard the mud, take care to remove the filter paper with mud cake, with the minimum of disturbance to the cake. Wash the filter cake on the paper with a gentle stream of water or with diesel oil (in the case of oil muds).

j)

Measure the thickness of the filter cake and report to the nearest 1/32”. Descriptions like hard, soft, tough, rubbery, firm, etc. may convey some idea of cake consistency.

High Pressure/High Temperature Test (not above 300°F) (Procedure Using Baroid Equipment) a)

Connect heating jacket and pre-heat to a temperature 10°F above the selected test temperature.

b)

Stir the mud sample and then fill cell to within 1/2” of the sealing ring to allow for expansion.

c)

Place filter paper on top of sealing ring and then seal down the top of the cell with the six “Allen” screws.

d)

Place the cell in the heating jacket with top and bottom “stem” valves closed. Place thermometer into the well provided.

e)

Place the pressure unit on the top valve and lock the bottom pressure receiver to the bottom valve.

f)

Apply 100 psi to both pressure units with stem valves closed.

g)

Open top stem valve only and apply 100 psi to the mud whilst heating to the selected temperature.

h)

When the mud reaches the desired temperature, increase the pressure on the top unit to 600 psi and open the bottom stem valve. Collect the filtrate for 30 minutes.

i)

If the pressure rises above 100 psi in the back pressure receiver, cautiously draw off filtrate until the pressure is 100 psi.

j)

At the end of the test, close both stem valves and bleed off the pressure in top and bottom units. Record the volume of filtrate.

Note: Stem valves are operated by turning 1/4 turn. Caution Pressure in the cell will still be 500 psi. Maintain the cell in the upright position and allow to cool to room temperature prior to opening.

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Calculation As the filter area of this unit is only 3.5 inches 2, the filtrate volume should be doubled to make it comparable with the low pressure test. An idea of the filter cake compressibility and quality can be gained by filtering at 200 and 100 psi.

5.

SAND CONTENT Procedure a)

Fill the glass measuring tube to the 50 ml mark with freshly agitated mud. Add water to the 100 ml mark. Close the mouth of the tube and shake vigorously.

b)

Pour the mixture onto the clean wet screen (200 mesh). Discard the liquid passing through the screen. Add more water to the tube, shake and again pour onto the screen. Repeat until tube is clean. Wash the sand retained on the screen with a fine stream of water to free it of any remaining mud.

c)

Fit the funnel upside down over the top of the screen. Slowly invert the tip of the funnel into the mouth of the glass tube.

d)

Wash the sand into the tube with a fine spray of water through the screen. Allow the sand to settle. Read the volume of sand report as sand content of mud.

Note: Use base oil instead of water for oil muds. 6.

SOLIDS CONTENT - RETORT (Baroid Retort) a)

Lift retort kit assembly out of heating compartment. Remove the mud chamber from the retort using the spatula.

b)

Clean and dry apparatus. The retort assembly must be absolutely dry.

c)

Pack upper chamber with dry steel wool.

d)

Homogenise the mud sample and remove air/gas by gently “tapping”.

e)

Fill chamber with mud (50 cm3 - the cylinder capacity should be checked periodically by filling it with water from a pipette). Replace lid allowing excess mud to escape.

f)

Place retort in heating assembly and switch on. Distillation should be complete in thirty minutes.

g)

Read the volumes of water and/or oil to the nearest 0.1 cm 3. Read the lower section of the meniscus.

Notes: i)

When reporting samples containing oil, some of the light fractions may be lost. A blank distillation of the oil only should be carried out to determine a correction factor; i.e. 50 cm 3 of oil distilled = 49.0 cm3 distillate Correction factor = 1.02

ii)

For seawater muds, a correction for the salt content of the mud must be made.

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MUD TESTING

Calculations a)

Let

A

= Volume of water - cm3

B

= Volume of oil - cm3

C

= Chloride content of mud filtrate - ppm

Total suspended solids = 100 - 10 (A + B + 0.1) - (0.76A X C) % Volume 100,000 b)

Oil/Water Ratio for OBM Let

7.

A

= Volume of water - cm3

B

= Volume of oil - cm3

Oil Content

=

B A+B

Water Content

=

A A+B

ALKALINITY FOR WATER BASED MUDS Equipment 0.02N Sulphuric Acid Phenolphthalein Methyl Orange 200 cm3 Conical Flask Range of Pipettes 1 - 5 cm3 25 cm3 Burrette

7.1

Filtrate Alkalinity a)

Phenolphthalein Alkalinity Pipette one or more ml of filtrate into the titration vessel. Add 3 drops of phenolphthalein. If the solution turns pink, add 0.02N sulphuric acid dropwise until the pink colour disappears (pH 8.3). Record the volume to the nearest 0.1 ml. Phenolphthalein Alkalinity, Pf

b)

=

Volume Acid Required Volume Sample

Methyl Orange Alkalinity To the filtrate used in step 1, add 3 drops of methyl orange and filtrate with 0.02N sulphuric acid until the colour changes from orange to red (pH 4.3). Record the volume of acid required including the volume to filtrate to the Pf end point. Methyl Orange Alaklinity, Mf

=

Total Volume of Acid Volume of Filtrate

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Mud Alkalinity Pipette one or more ml of mud into the titration vessel. Add 50 cm3 of distilled water and 3 drops of phenolphthalein. If the solution turns pink, titrate with 0.02N sulphuric acid until the pink colour disappears. Record the volume of acid used. Phenolphthalein Alkalinity of Mud, PM

7.3

=

Volume of Acid Required Volume of Mud

Lime Content Free lime content can be calculated as follows: Lime ppb = 0.26 (PM - FW Pf) Where FW = Volume fraction of water in mud.

8.

CARBONATE DETERMINATION IN WATER BASED MUD BY THE GARRETT GAS TRAIN

8.1

Equipment

8.2

8.3

1.

The Garrett Gas Train apparatus consists of: a transparent plastic gas train, an inert gas supply (N2O) and pressure regulator, a CO2 Drager tube and a Drager hand vacuum pump.

2.

Drager CO2 analysis tube, CH-30803, “CO20.01 A”.

3.

Drager one liter gas bag, 6762425.

4.

Drager “Multigas Detector” hand vacuum pump, Model 31.

5.

Glass 8 mm stopcock (2-way bore).

6.

Hypodermic syringes: Two 10 ml with 18 gauge needle (for acid), one 2 1/2 ml (for sample).

7.

N2O gas cartridges (e.g. “Whippets” 561241 by Walter Kidde & Co. Inc., Bellville, N J).

Reagents 1.

Sulphuric acid: approximately 5 N, reagent grade.

2.

Octanol defoamer in a dropper bottle.

3.

Deionized water.

Procedure 1.

Be sure the gas train is clean, dry, and on a level surface.

2.

With regulator backed off, install and puncture a N2O (“Whippet”) gas cartridge.

3.

Add 20 ml deionized water to Chamber 1.

4.

Add 5 drops of octanol defoamer to Chamber 1.

5.

Install the top of the gas train and hand-tighten evenly to seal O-rings.

6.

Attach the flexible tubing from the regulator onto the dispersion tube of Chamber 1.

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MUD TESTING Inject with syringe an accurately measured sample of filtrate into Chamber 1 (refer to Table 1). Flow carrier gas through train for one minute to purge air from system. Stop gas flow. Table 1 Drager Tube Identification Sample Volumes and Tube Factor to be Used for Various Carbonate Ranges 1

2

3

4

Carbonate Range (mg/l)

Sample Volume (ml)

Drager Tube Identification

Tube Factor

25 to 750 50 to 1500 250 to 7500

10.0 2.5 1.5

“CO2 0.01% “A”

25,000

8.

Install one end of a piece of flexible tubing onto the stopcock which is fitted directly into the gas bag. Have the gas bag fully collapsed. Fit the other end of the tubing onto the outlet tube of Chamber 3.

9.

Slowly inject 10 ml sulphuric acid solution into Chamber 1 through rubber septum using the hypodermic syringe and needle. Gently shake gas train to mix acid with sample in Chamber 1.

10.

Open the stopcock on the gas bag. Restart N2O flow gently and allow gas bag to fill. When bag is full, do not burst it, shut off N2O flow and close the stop-cock. Immediately proceed to Step 11.

11.

Remove the tubing from Chamber 3 outlet and re-install it onto the upstream end of the CO2 0.01/A Drager tube. (Observe that the arrow indicates gas flow direction.) Attach Drager hand pump to other end of Drager tube.

12.

Open stopcock on bag. With steady hand pressure fully depress the hand pump, then release so that gas flows out of the bag and through the Drager tube. Operate hand pump ten strokes, which should essentially empty the gas bag.

13.

Observe a purple stain on the Drager tube if CO2 was present in the gas bag. Record the stain length in units marked on the Drager tube.

14.

Using the measured sample volume, the Drager tube’s purple stain length and tube factor of 25,000 (see Table 1), calculate the soluble carbonates in the filtrate sample using equation below: mg/l of CO3

15.

=

(Tube Stain Length) x (25,000) Sample Volume, ml

To clean the gas train, remove the flexible tubing and remove the top. Wash out the chamber with warm water and mild detergent, using a brush. Use a pipe cleaner to clean the passages between chambers. Wash, rinse and then blow out the dispersion tubes with air or N2O gas. Rinse the unit with deionized water and allow to drain dry.

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MUD TESTING

GARRETT GAS TRAIN EQUIPMENT

RUBBER SEPTUM

ACID

STOPCOCK

SAMPLE OF FILTRATE

GAS BAG

FILLING BAG

GAS BAG

DRAGER TUBE CH-30803 CO2

PURPLE STAIN

DRAGER HAND PUMP

EMPTYING BAG

2179 / 79

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9.

CATION EXCHANGE CAPACITY FOR WATER BASED MUDS

9.1

Apparatus and Chemicals Pipette, 1 ml Burette, 10 ml Conical Flask, 200 ml Measuring Cylinder, 50 ml Hot Plate Filter Paper, Whatmans No. 1, 11 cm diameter Methylene Blue Solution (1 ml = 0.01 milliequivalents) Hydrogen Peroxide, 3% solution Dilute Sulphuric Acid : approximately 5N

9.2

Procedure a)

Add 1 ml of drilling fluid to 10 ml of distilled water in a Conical flask.

b)

Add 15 ml of hydrogen peroxide and 0.5 ml of sulphuric acid.

c)

Mix by swirling, then place on hot plate and boil gently for 10 minutes.

d)

Dilute to 50 ml with distilled water.

e)

Add methylene blue solution from the burette to the flask. After each addition of 0.05 ml, swirl the contents of the flask for about 30 seconds. While the solids are still suspended, remove one drop of liquid with a glass rod and place the drop on a filter paper. The end point of the titration is reached when dye appears as a blue ring surrounding the dyed solids.

f)

When the blue tint spreading from the spot is detected, shake the flask for an additional 2 minutes and place another drop on the filter paper. If the blue ring is again seen, the end point has been reached. If the ring does not appear, continue as before until a drop taken after shaking 2 minutes shows the blue tint.

g)

Report the cation exchange capacity of the mud as the methylene blue capacity, calculated: =

ml of methylene blue used ml of mud used

This can be expressed as the bentonite content of the mud, if other absorptive materials are not present in significant amounts. Bentonite lb/bbl = methylene blue capacity x 5.

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10.

DETERMINATION OF CHLORIDE ION FOR WATER BASED MUDS

10.1

Apparatus and Chemicals Titration Flask, 200 ml Pipettes, 1 ml, 2 ml Burette, 10 ml 0.02N Sulphuric Acid 0.0282N Silver Nitrate Solution Phenolphthalein Indicator Potassium Chromate Indicator Distilled Water

10.2

10.3

Procedure a)

Measure 1 or 2 ml of filtrate into the titration flask.

b)

Add 25 ml of distilled water.

c)

Add 4 drops of phenolphthalein indicator and titrate with 0.02N sulphuric acid until pink colour disappears.

d)

Add 5 to 10 drops of potassium chromate.

e)

Titrate with 0.0282N silver nitrate solution until a colour change from yellow to orange red is obtained which remains for 30 seconds.

f)

Record ml of silver nitrate solution added.

Calculation Cl–, mg/l

=

(ml of silver nitrate) x 1000 ml of filtrate sample

Note: For muds with a high chloride content, 0.282N AgNO3 should be used. Cl– mg/l

=

(ml of silver nitrate) x 10000 ml of filtrate

11.

TOTAL HARDNESS

11.1

Apparatus and Chemicals 0.01M Versenate Solution (1 ml = 1 mg CaCO3) Buffer Solution Hardness Indicator - Eriochrome Black T Titration Flask, 200 ml

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Pipettes, 1 ml, 2 ml, 5 ml Burettes, 10 ml Graduated Cylinder, 50 ml Distilled Water 11.2

11.3

Procedure a)

Measure one or more ml of sample into the titrating flask.

b)

Add 50 ml of distilled water.

c)

Add 2 ml of buffer solution.

d)

Add sufficient amount of hardness indicator to give a strong wine red colour.

e)

Add versenate solution dropwise, swirling the titration flask vigorously until a colour change to blue is observed.

f)

Note ml of versenate added.

Calculation Hardness as CaCO3 mg/l =

ml versenate x 1000 ml sample

*Calcium as Ca++, mg/l

400 x ml versenate ml sample

=

* This is in fact a total of Ca++ plus Mg++. 12.

KCL CONTENT

12.1

Equipment Sodium Perchlorate (150g in 100 cm3 distilled water) Centrifuge - 1800 rpm 10 cm3 Centrifuge Tubes

12.2

12.3

Calibration a)

Formulate a series of KCL solutions covering the expected working range.

b)

Add 7 cm3 of the solution to a centrifuge tube and 3.0 cm3 sodium perchlorate.

c)

Centrifuge for 1 minute at 1800 rpm.

d)

Plot a calibration curve of KCL concentration versus precipitate volume.

KCL Content of Mud a)

Add 7 cm3 of filtrate to a centrifuge tube and 3.0 cm3 sodium perchlorate.

b)

Centrifuge for 1 minute at 1800 rpm.

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From calibration plot, read off KCL concentration.

Note: If only a hand operated centrifuge is available, a KCL solution of known concentration similar to the expected value of the mud should be run with the filtrate for comparison. 13.

EXCESS POLYACRYLAMIDE CONTENT OF MUD

13.1

Apparatus and Chemicals Pipettes, 2 ml, 10 ml Centrifuge Tubes, 10 ml Centrifuge 0.2N Hydrochloric Acid Cresol Red Indicator Floc Developer A Floc Developer S

13.2

Procedure a)

To 10 ml of filtrate add 3 drops of Cresol red indicator.

b)

Add 0.2N HCL drop by drop until a yellow end point is reached. (An exact end point can be obtained with a pH meter: pH 6.3 - 6.8.)

c)

Add 2 ml of Floc Developer A, roll gently, allow to stand, roll again.

d)

Centrifuge for 1 minute, pour off liquid into another centrifuge tube.

e)

To this second tube containing liquid from step (4) add 2 ml of Floc Developer S, roll gently, allow to stand for 3 to 4 minutes, roll again.

f)

Centrifuge for 1 minute.

g)

Read Floc volume as lb/bbl polyacrylamide (e.g. 1 ml = 1 lb/bbl).

Note: In low fluid loss muds (8 ml and below) allow the sample containing Floc Developer S to stand for 2 hours before centrifuging to obtain the polyacrylamide content. (In this case the reading is only qualitative, an indication that there is available polymer in the mud filtrate.) 14.

CALCIUM SULPHATE (GYPSUM) a)

Add 5 cm3 of mud to 245 cm3 distilled water and mix for 5 minutes on a Hamilton Beach Mixer, filter, discarding cloudy portion.

b)

Titrate 10 cm3 of the filtrate to the versenate end point as described in the “total hardness” section.

c)

Titrate 1 cm3 of original mud filtrate to the versenate end point.

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Calculation Total calcium sulphate = 2.38 Vt Undissolved calcium sulphate = 2.38 Vt - 0.48 Vf FW Where: Vt

=

cm3 of versenate required to titrate 10 cm3 of the dilute mud filtrate.

Vf

=

cm3 of versenate required to titrate 1 cm3 of original mud filtrate.

FW

=

Volume fraction of water in mud from retort analysis.

15.

LIME CONTENT OF OBM

15.1

Equipment 75/25 Toluene/Isopropyl Alcohol Glass Sample Bottle Phenolphthalein 0.1N Sodium Hydroxide 0.1N Sulphuric Acid

15.2

Procedure a)

To 50 cm3 of 75/25 Toluene/Isopropyl alcohol, add 1 cm3 of mud and disperse.

b)

Add 100 cm3 distilled water, 2 - 3 drops phenolphthalein plus 5 cm3 0.1N sulphuric acid.

c)

Shake vigorously for 1 minute. If solution is still red add a further 5 cm3 0.1N sulphuric acid and so on until the pink colour disappears.

d)

Titrate with 0.1N sodium hydroxide until the first permanent pink end point is reached.

Alkalinity Mp = volume 0.1N sulphuric acid - volume 0.1N sodium hydroxide. Excess Lime ppb = Mp x 1.3. 16.

ELECTRICAL STABILITY (Fann) a)

Place probe in freshly stirred mud.

b)

Press down red button for 10 seconds.

c)

Slowly increase voltage until red light appears.

Electrical stability = dial reading x 2.

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17.

GARRETT GAS TRAIN ANALYSIS OF SULPHIDES IN WATER BASED MUD

17.1

Equipment The following materials are required to perform the sulphide analysis using either a filtrate or a mud sample. 1.

The Garrett Gas Train (GGT) apparatus consists of: A transparent gas train, an inert gas supply, and pressure regulator, a floating ball flowmeter, and a Drager tube.

2.

Drager H2S Analysis Tubes: 1. 2.

17.2

Low range - marked H2S 100/a - (No CH-291-01). High range - marked H2S 0.2% - (No CH-281-01).

3.

Lead acetate paper disks.

4.

Hypodermic syringes: two 10 ml with 18 gauge needle (for acid) and one 2 1/2 ml (for sample).

5.

Sulphuric acid: approximately 5 N, reagent grade.

6.

Octanol defoamer in a dropper bottle.

Procedure 1.

Be sure the gas train is clean, dry and on a level surface.

Note: Moisture in the flowmeter can cause the ball to float erratically. 2.

With the regulator backed off, install and puncture a CO2 cartridge.

3.

Add 20 ml deionized water to Chamber 1.

4.

Add 5 drops octanol defoamer to Chamber 1.

5.

See Table I for sample volume and type of Drager Tube required for the expected sulphide range. Use whole mud for total sulphides and filtrate for soluble sulphides. Select the proper type Drager tube. Break the tip from each end of the tube. Table I Drager Tube Identification, Sample Volumes and Tube Factors to be Used for Various Sulphide Ranges 1

2

3

4

Sulphide Range (mg/l)

Sample Volume (ml)

Drager Tube Identification (See Tube Body)

Tube Factor

1.5 to 30 3 to 60 6 to 120

10.0 5.0 2.5

H2S 100/1

15

60 to 1020 120 to 2040 240 to 4080

10.0 5.0 2.5

H2S 0.2%/A

600*

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The Tube Factor 600 is based on a Batch Factor (stenciled on box) of 0.40. For another Batch Factor (as stenciled on box), a corrected Tube Factor should be calculated: Corrected Tube Factor

=

600 x Batch Factor 0.40

6.

Install the Drager tube, with the arrow pointing downward, into the bored receptacle. Likewise, install the flowmeter tube with the word TOP upward. Be sure O-rings seal around the body of each tube.

7.

Measure the sample into Chamber 1.

8.

Install the top of the gas train and hand tighten all screws evenly to seal.

9.

Attach the flexible tubing to the dispersion tube and to the Drager tube.

Note: Use only latex rubber or inert plastic tubing. Do not clamp flexible tubing; unclamped tubing provides pressure relief in event of over-pressurisation. 10.

Adjust the dispersion tube in Chamber 1 to approximately 0.5 cm above the bottom.

11.

Gently flow CO2 for a 10 second period to purge air from the system. Check for leaks. Shut off CO2.

12.

Slowly inject 10 ml sulphuric acid solution into Chamber 1 through rubber septum using the hypodermic syringe and needle.

13.

Immediately restart CO2 flow. Ajust the rate such that the ball stays between the lines of the flowmeter.

Note: One CO2 cartridge should provide about 15-20 minutes of flow at this rate. 14.

Observe changes in appearance of the Drager tube. Note and record the maximum Darkened length (in units marked on the tube) before the front starts to smear. Continue flowing for a total of 15 minutes, although the front may attain a diffuse and feathery colouration. In the high-range tube an orange colour may appear ahead of the black front if sulphides are present in the sample. The orange region should be ignored when recording DARKENED LENGTH.

15.

Using the measure Sample Volume, the Drager tube’s maximum Darkened Length (in units marked on the tube) and the Tube Factor from Table 1, calculate sulphides in the sample: GGT Sulphides, mg/1 = Darkened Length x Tube Factor Sample Volume, ml

Note: A lead acetate paper disk fitted under the O-ring of Chamber 3 can be substituted for the Drager tube in the Garrett Gas Train. The lead acetate paper, although not preferred for quantitative analysis, will show qualitatively the presence or absence of sulphides in the sample. A dark discoloration of the paper is positive indication of sulphides. After the positive indication, the Drager tube should be used for quantitative analysis. 16.

To clean the gas train, remove the flexible tubing and remove the top. Take the Drager tube and flowmeter out of the receptacle and plug the holes with stoppers to keep them dry. Wash out the chambers with warm water and mild detergent, using a soft brush. Use a pipe cleaner to clean

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MUD TESTING the passages between the chambers. Wash, rinse and then blow out the dispersion tube with air or CO2 gas. Rinse the unit with deionized water and allow to drain dry.

18.

GARRETT GAS TRAIN ANALYSIS OF SULPHIDE IN OIL BASED MUD

18.1

Equipment The following materials are required to perform the sulphide analysis using an oil-mud (not filtrate) sample in the gas train. a)

The Garrett Gas Train (GGT).

b)

Drager H2S Analysis Tubes: 1. 2.

18.2

Low range - marked “H2S 100/a” - No. CH-29101. High range - marked “H2S 0.2%A” - No. CH-28101.

c)

Citric acid solution, 2 molar, containing a demulsifier. This is prepared by dissolving 420g reagent grade citric acid, C6H8O7 H20, into 1000 ml de-ionized water. To this solution, stir 25 ml. Dowell Fluid Services Oil - mud demulsifier.

d)

Octanol in a dropper bottle, as a defoamer.

e)

Hypodermic syringes: One 20 ml syringe for citric acid measurement and several (2.5, 5.0 and 10.0 ml) disposable syringes for oil mud sample measurements.

f)

Magnetic stirrer with plastic or glass covered stirring bar ( 1/4 inch by 1 inch) to fit into GGT Chamber 1.

g)

Teflon sample injection tube or “needle”, KF 11 TF, 33817 (cut to a 6” length) internal diameter 0.095 inch, wall thickness 0.012 inch, Hamilton Co, Reno, Nev.

Method The Garrett Gas Train separates the gas from the liquid, thereby preventing contamination of the H2S detector by the liquid phase. A Drager tube is the preferred H2S detector for quantitative sulphide analysis, although a lead-acetate paper disk can be accommodated in the Garrett Gas Train for positive or negative determination of the presence of H 2S. If a positive indication of sulphide is noted by discoloration of the lead acetate paper, a Drager tube should be used in a retest of the sample for quantitative analysis. A Drager tube responds to H2S by progressively darkening along its length as the H2S reacts with the reagent. Two types of Drager tubes will span a sufficiently wide range for sulphide analysis of muds. The low range Drager tube, “H2S 100/a”, is white until H2S turns it brownish black. The high range Drager tube, “H2S 0.2%/A”, is pale blue until H2S turns it jet black. No other known common mud component or contaminant causes this coloration of the Drager tubes as does H2S. The oil mud sample to be analysed is the whole mud, which consists of liquid and solid phase materials. The reason for using 2-M citric acid (with pH 1.8) for this test is to avoid generating spurious sulphides from certain metal sulphide minerals commonly present in earth materials and in commercial barite used in muds. (If sulphuric acid were used, it is strong enough to liberate H2S from these minerals.) The Dowell Fluid Service Oil Mud Demulsifier is inert to H2S and is an aid in preventing oil wet solids in the mud from agglomerating and sticking onto the GGT walls.

18.3

Procedure 1.

Arrange the magnetic stirrer and gas train body so that the stir bar will freely rotate, so vigorously agitate the contents of Chamber 1.

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2.

With the gas regulator backed off, install and puncture a CO2 cartridge in the carrier gas assembly. Do not use air as a carrier gas.

3.

Arrange the plastic injection tube (for attachment to a hypodermic syringe) through the rubber septum on the top of Chamber 1 to allow the mud sample to be slowly injected into Chamber 1.

4.

Add 20 ml of 2-M citric acid solution containing the demulsifier into Chamber 1.

5.

Add 10 drops of octanol to the contents of Chamber 1. Be sure that the stir bar is in Chamber 1.

6.

Select a Drager tube (low or high range) based on Table A.1 to match the expected levels of sulphides, and select a mud sample size of either 2.5, 5.0 or 10 ml based on Table 1.

7.

Break the tip of each end of the Drager tube, and install it with the arrow pointing downward onto the bored receptacle. Similarly, install the flowmeter tube with the word “Top” upward. Be sure O-rings seals around the body of each tube.

8.

Install the top of the gas train, and hand tighten all screws evenly to seal.

9.

Attach the flexible tubing to the dispersion tube and to the Drager tube.

Note: Use only latex rubber or flexible, inert plastic tubing. Do not clamp this flexible tubing; unclamped tubing provides pressure relief in the event of over-pressurisation. 10.

Adust the dispersion tube in Chamber 1 to approximately 3.0 cm above the bottom to clear the stir bar.

11.

Put the sample into the syringe, and place the syringe into the injection tube. Hole the syringe plunger in place with the hand. Gently flow the gas for a 10 second period to purge air from the system. Check for leaks. Shut off the gas. Start rapid stirring of the contents of Chamber 1.

12.

Slowly inject a measured volume of oil mud into Chamber 1 through the injection tube using a hypodermic syringe. (Keep the injection tube sealed with a syringe during the test. A rubber band can be used to hold the syringe in place.) Stir at least 5 minutes or until the sample is well dispersed with no obvious oil drops.

13.

Restart the carrier gas flow. Adjust the rate between 200 to 400 ml per minute, or keep the flowmeter ball between the red lines.

Note: One CO2 cartridge should provide about 15 to 20 minutes of flow at this rate. 14.

Observe changes in the appearance of the Drager tube. Note and record the maximum Darkened Length (in units marked on the tube) before the front starts to smear. Continue the gas flow for a total of a least 15 minutes. With prolonged flow, the stain front may attain a diffuse and feathery coloration. In the high range tube, an orange colour may appear ahead of the black front if sulphites (SO2) are present in the sample. The orange region should be ignored when recording the Darkened Length.

15.

Using the measured Sample Volume, the Drager tube’s maximum Darkened Length, and the Tube Factor from Table A.1, calculate the active sulphides as H2S in the sample. GGT/H2S, mg/l

=

(Darkened Length*) (Tube Factor) (Sample Volume, ml)

* In units marked on the tube.

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MUD TESTING Table 1 Drager Tube Identification, Sample Volumes and Tube Factors to be Used for Various Sulphide Ranges

*

1

2

3

4

Sulphide Range (mg/l)

Sample Volume (ml)

Drager Tube Identification (See Tube Body)

Tube Factor

1.5 to 30 3 to 60 6 to 120

10.0 5.0 2.5

H2S 100/a

12

60 to 1020 120 to 2040 240 to 4080

10.0 5.0 2.5

H2S 0.2%/A

600*

The Tube Factor 600 is based on a Batch Factor (stenciled on box) of 0.40. For another Batch Factor (as stenciled on the box), a corrected Tube Factor should be calculated: Corrected Tube Factor

=

600 x Batch Factor 0.40

19.

FIELD PROCEDURE FOR ZINC CARBONATE IN WATER BASED MUD

19.1

Equipment 1. 2. 3. 4. 5. 6. 7. 8. 9.

150 ml beaker. Graduated cylinders (10 ml, 25 ml and 100 ml). Field mixer with powerstat or magnetic stirrer. 10 ml syringe. 20 ml syringe. Large 4” plastic funnel. Fluted filter paper (S & S No 588 size 18.5 cm). pH paper. 10 and 20 ml volumetric pipettes.

Solutions 1. 2. 3. 4. 5. 6. 7. 8. 9. 19.2

Glacial acetic acid. Ammonium Hydroxide (concentrated). Distilled water. Calcium Solution II (30% NaCN Solution). 10% Ammonium Fluoride. Manver indicator (from Hardness Kit). 4% Formaldehyde solution. 0.01 M Versentate solution (from Hardness Kit). Calcium Solution I (10% Hydroxylamine Hydrochloride).

Procedure 1.

From well mixed sample take 10 ml using a syringe. (Note: If total hardness exceeds 50,000 mg/l Ca++, take a 5 ml sample).

2.

Place in 150 ml beaker or other suitable container.

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3.

Dilute to 40 ml with distilled water.

4.

Add 10 ml Glacial acetic acid.

5.

Stir for 10 minutes with mixer or magnetic stirrer. If neither is available, mix with stirring rod.

6.

Add 15 ml Ammonium Hydroxide. Made sure solution is above pH 9 before proceeding to next step.

7.

Add 3 droppersful of Calcium Solution II in that order.

Note: Calcium Solution II is extremely poisonous (Sodium Cyanide). Do not add to acidic solution as Cyanide gas will be liberated. 8.

Add 10 ml 10% Ammonium Flouride solution.

Note: If total hardness exceeds 100,000 mg/l Ca++, add 20 ml 10% Ammonium Fluoride solution. Ammonium Fluoride is also poisonous. Take same precautions as above.

19.3

9.

Bring up to 100 ml with water using either a 100 ml volumetric flask or 100 ml graduate.

10.

Mix well and filter through S & S fluted paper into a dry, clean beaker or suitable container.

11.

Take 10 ml or 20 ml of filtrate and place in clean beaker or flask.

12.

Dilute with distilled water up to about 40 ml.

13.

Add a few drops of Manver Indicator. If solution is blue, proceed directly to Step 14. If solution is red, titrate slowly with Standard Versenate to the regular blue endpoint; the amount of Versenate solution does not need to be recorded as it is not used in the calculations.

14.

Add 5 ml concentrated Ammonium Hydroxide. The pH should be between 10 and 11.

15.

Add 5 ml 4% Formaldehyde Solution.

16.

Let stand at least 2 minutes. Solution will turn from blue to wine-red in zinc is present.

17.

Titrate with Versenate until wine-red changes to sky blue (similar to the hardness endpoint).

Calculations lbs/bbl ZnCo3

20.

=

44 x ml Versenate ml sample x ml Filtrate

OIL CONTENT OF CUTTINGS DISCHARGED FROM THE SHALE SHAKERS The procedure outlined is the DOE procedure and must be followed. The analysis is to be performed on a daily basis. On days when in excess of 300m (1000 ft) is drilled, the analysis must be performed twice.

20.1

Sampling A representative bulk sample of at least 0.5 kg to 1 kg should be taken and must include material from each deck of all the shale shakers. This is best achieved by “scanning” a suitable container, preferably a wide tray which will retain all the material, i.e. both solids and liquids, beneath the discharge from the shakers.

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The sample should then be transferred to a smooth, clean surface (e.g. heavy gauge polythene, 2-3 mm in thickness) ensuring that all drained oil is transferred with the solids. The whole bulk sample(s) should then be thoroughly mixed, ensuring that any drained oil is fully incorporated. Quickly dip-sample the material and fill the sample containers. The containers used will depend on the analytical method and whether the samples are to be analysed immediately or taken ashore for check analysis or reference. 20.2

Analysis a)

Apparatus Proprietary mud, oil and water retort kit with at least three mud chambers. A 50 ml mud chamber should be used. The distillate receiver must be an accurately calibrated 20 ml or 50 ml measuring cylinder calibrated in 1.0 ml divisions (in place of the receiver normally used with the retort). A balance capable of weighting to an accuracy of 0.1g under offshore conditions. An integrating balance system is recommended.

b)

Method Weigh the distillate receiver and mud chamber with lids. Record the weighing. Fill the mud chamber with cuttings as completely as possible, replace the lids and clean off any adhering mud and oil. At least three chambers should be filled, one for immediate analysis and the others to be held in reserve in case of accidents etc. Re-weigh the filled chambers and record the weighings. Place the chamber in the heating compartment, switch on the heater and allow to distill for at least 25 minutes. Collect the distillate in the weighed, graduated receiver. Switch off the heater, remove the mud chamber and allow to cool. Read off the volume of the water collected and re-weigh the distillate receiver with its contents and record the results. The cylinder should be at ambient temperatures before the readings are taken.

20.3

Calculations The content of oil in the cuttings should be expressed as grams of oil per kilogram of DRY RETORTED SOLIDS: That is

20.4

Weight of oil (g) Weight of dry retorted solids (g)

x 1000

Check Calibration The heating element in the retort kit can decline in efficiency over a period of time and this needs to be checked. Such checks should be carried out, for each well drilled with oil based mud. i) ii)

Prior to drilling with OBM. At the completion of the well.

To calibrate a retort the following mixture should be mixed on a Hamilton Beech Mixer at the high speed setting, adding each component in order as listed below:

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Base Oil Organophillic Clay Emulsifier Lime Fresh Water Wetting Agent Barite

106 ml 1.0 g 3.0 ml 2.0 g 28 ml 3.0 g 750 g

Mixing notes: 1.

The barite should be added in stages, until the mixer can no longer incorporate the solids (approx. 650g), the remaining barite should be thoroughly mixed in with a spatula.

2.

The final mixture should be of a highly viscous, grainly-looking, semi-solid nature, but fluid enough to allow proper filling of the retort cup.

The above mixture should yield a measured oil/water ratio of 80/20. Solids content is 56%. Total volume of the mix is 320 ml and thus one mix should be sufficient for calibration of a 50 ml retort six times (allowing for the inevitable losses). The measured figure of oil on dry retorted solids should be within ± 10 g/kg of the calculated value. 20.5

Reporting Reporting is to be carried out using the forms, the proforma for which can be found in the BP Reporting Procedures Manual.

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SOLIDS CONTROL

1.

INTRODUCTION

1.1

The aim of any efficient solids removal system is to retain desirable components of the mud system for correct mud property control, but to be capable of separating out and discharging unwanted drilled solids and contaminants. The benefits of an effective solids removal system cannot be overstressed and include reduced overall mud costs, reduced chances of stuck pipe and associated hole problems, increased penetration rates and increased equipment life due to reduced abrasiveness.

1.2

In order to perform effectively, solids removal equipment must be well maintained and its layout incorporated into a systematically designed mud system. It must be capable of handling the maximum conditions expected related to circulating rates and solids production capacity (instantaneous penetration rates), yet retain the versatility of coping with the demands of various mud types and different hole sections, such that optimum solids removal is obtained on the first circulation through the equipment.

1.3

There are four stages of mechanical contaminant treatment which can be applied to drilling fluids: a) b) c) d)

Screen separation of large cuttings, i.e. shale shakers. Settling separation in non-stirred compartments, i.e. sand traps. Removal of gaseous contaminants by vacuum or otherwise, i.e. degassers. Forced settling by the action of centrifugal devices, i.e. hydrocyclones and centrifuges.

1.4

Figure 1 shows a typical layout for a solids removal system. Figure 2 shows the particle sizes removed by each piece of solids control equipment, and the API particle size classification.

1.5

The solids separation efficiency of any particular piece of solids removal equipment can be defined in terms of a cut point. Cut point, usually expressed in microns, refers to the particle size that has a specified concentration (as a percentage of the feed concentration) reporting to the underflow (discharge) stream of a particular device. The most commonly referred to cut point is the D50, which is equivalent to the particle size that has an equal concentration (50% of feed) in both the underflow and overflow. It is often useful to compare the D50 value with the D10 and D90 values (representing particle sizes distributed 10% and 90% in the underflow respectively). This comparison defines the sharpness of separation of a piece of solids control equipment. Consider a square mesh shaker screen and a fluid containing an equal size distribution of spherical particles. There will clearly be a specific particle size that will pass through the mesh, above this size all particles will be retained on the screen and discharged. For such a situation the D10, D50 and D90 will be identical. For a hydrocyclone, the sharpness of separation is less well defined and for the same fluid system the D10 may be substantially lower than the D50, which in turn will likely be substantially lower than the D90. In other words a very high percentage of the large particles entering the cone are separated and discharged, whereas a much lower percentage of the fines undergo effective separation and discharge. These results are shown graphically below.

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100

Hydrocyclone

Shale Shaker

90 Percentage of specified particle size reporting to underflow

50

10 0 Particle Size (microns)

Note that the gradient of the curve defines the sharpness of separation.

2179 / 78

SUBJECT:

DISCHARGE

SAND TRAP UNDER SCREENS NOT STIRRED

SHALE SHAKERS

DEGASSER SUCTION 1

2

STIR

OVER FLOW

DESANDER SUCTION NOT DEGASSING

EDUCTOR 3 PUMP SUCTION

4

STIR

*

STIR

DESANDER SUCTION

WEIGHT SALVAGE

5

STIR

DESILTER SUCTION

CENTRIFUGE SUCTION

6

ACTIVE PIT SYSTEM

STIR

STIR

ADJUSTABLE

(DEGASSING)

CENTRIFUGE

DESANDER PUMP

DESILTER PUMP

DISCHARGE

DISCHARGE

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OVERFLOW WHEN DEGASSING UNDERFLOW WHEN NOT DEGASSING

:

*

Rev.

TANK UNDERFLOW (EQUALISATION)

3 of 11

GATE VALVE

:

KEY

DISCHARGE (LIQUID OR SOLID FRACTION)

Page

RETURN MUD FLOW

DESILTER

DESANDER

BP EXPLORATION

SCREEN

DRILLING MANUAL

SHAKER TROUGH

FIG. 1 SOLIDS REMOVAL EQUIPMENT SCHEMATIC

MUD CLEANER PUMP

SOLIDS CONTROL

MUD CLEANER

DEGASSER

SUBJECT:

PARTICLE SIZES REMOVED BY PROCESSING EQUIPMENT DESILTER

60 - 80µ ( > 200µ WITH OBM )

74µ

2 - 5µ

PARTICLE SIZE CUT BY EQUIPMENT

BP EXPLORATION

200 - 220µ

MUD CLEANER CENTRIFUGE ( 200 MESH SCREEN )

DRILLING MANUAL

178µ

DESANDER

SOLIDS CONTROL

SHALE SHAKER ( 80 MESH SCREEN )

API CLASSIFICATION OF PARTICLE SIZE

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API SPECIFICATION FOR BARITE: MINIMUM 97% MUST PASS THROUGH 200 MESH SIEVE ( ie 97% LESS THAN 74µ ) MAXIMUM 10 ± 5% RETAINED ON 325 MESH SIEVE ( ie AT LEAST 85% LESS THAN 44µ )

:

SIEVE SIZE —————— 10 MESH 60 MESH 200 MESH 325 MESH

Page

CLASSIFICATION ————————— COARSE INTERMEDIATE MEDIUM FINE ULTRAFINE COLLOIDAL

FIGURE 2

SIZE ——— > 2000µ 2000 - 250µ 250 - 74µ 74 - 44µ 44 - 2µ 2 - 0µ

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SOLIDS CONTROL

2.

SOLIDS CONTROL EQUIPMENT - OPERATIONAL GUIDELINES

2.1

Flowlines Flowlines, "Gumbo" traps, and shaker header boxes must be cleaned out as necessary on connections/ trips, to prevent massive solids build-up restricting working capacity. Jet-lines, if fitted, must be effective and regularly inspected.

2.2

Shale Shakers i)

Screen sizes must be optimised for maximum cuttings separation without screen overloading or mud losses over the screens. Mud type and rheology, circulation rate, formation returns and penetration rates must also be considered, and the finest mesh screens then selected that meet these conditions. Adequate stocks of spare screens should be maintained such that optimum screen sizes can be used at all times.

ii)

The top screen on a double deck shaker should be of coarse mesh and used as a "scalping" device, removing the bulk of the large cuttings from the mud to enable the finer screen on the lower deck to operate more efficiently.

iii)

The fluid front of the mud on the top screen should cover approximately 50-60% of the screen area, and on the lower screen 60-65% of the screen area. This allows the sharpest cut point compatible with maintaining a safety margin for flow surges and still permits "dry" solids to be conveyed for some distance and so enhance "shake-off" of liquid mud.

iv)

In the event of sand blinding of a screen consider changing to screens of a finer mesh. Rectangular mesh screens outperform equivalent square mesh screens where sand blinding is a problem.

v)

If mud viscosity produces screen blinding consider reducing the circulation rate whilst maintaining efficient hole cleaning, or change to a coarser screen. With new water based polymer mud and oil based mud, commence circulation using coarse screen dressed shakers and move to finer mesh screens as the mud shears in and warms up after 1 or 2 circulations.

vi)

Shaker screens should be regularly washed down on connections/trips for prolonged life and to maintain efficient operation. Cuttings should never be allowed to dry hard upon the screens when the shakers are not in use.

vii)

Never run the shakers dry (i.e. without fluid flow across them). This leads to increased wear and premature screen failure.

viii)

Distribution gates allowing returns flow from the header box to the shakers should be adjusted such that total returns flow is distributed evenly onto all available shakers. On semi-submersible rigs in conditions of extreme weather, the pitch/roll of the rig will create surges of flow onto specific shakers, and under these conditions coarser screens may have to be used to prevent mud losses.

ix)

The shaker screens should never be bypassed, unless absolutely necessary when running LCM in the mud. Under no circumstances should operations continue with a torn or ineffective screen.

x)

Table 1 shows the performance characteristics of square and rectangular mesh market grade screens, along with the API and common manufacturers' designations. Note that the flow capacity of a screen is directly related to the conductance and not to the percentage open area. Multi-layered screens, usually consisting of a coarse market grade backing cloth (for strength) and finer mesh tensile bolting cloth upper layers, offer significant improvements in solids separation and resistance to blinding, but are significantly more expensive than the single mesh screens.

SUBJECT:

SQUARE MESH Manufacturers' Reference Numbers** Conductance kD/mm

API Designation*

Baroid

Brandt

Derrick (panelled)

SWACO

SWECO

Thule (HS or PTS)

10 x 10 20 x 20 30 x 30 40 x 40 50 x 50 60 x 60 80 x 80 100 x 100 120 x 120

0.025 0.016 0.013 0.010 0.009 0.0075 0.0055 0.0045 0.0037

2108 863 515 381 279 234 178 140 117

56.3 46.2 37.1 36.0 30.3 30.5 31.4 30.3 30.7

75.6 21.3 12.6 7.5 4.4 3.7 2.9 2.2 1.9

10 x 10 (2108 x 2108, 56.3%) 20 x 20 (863 x 863, 46.2%) 30 x 30 (515 x 515, 37.1%) 40 x 40 (381 x 381, 36.0%) 50 x 50 (279 x 279, 30.3%) 60 x 60 (234 x 234, 30.5%) 80 x 80 (178 x 178, 31.4%) 100 x 100 (140 x 140, 30.3%) 120 x 120 (117 x 117, 30.7%)

191-201 191-202 191-203 191-204 191-205 191-206 191-208 191-210 191-212

S10 S20 S30 S40 S50 S60 S80 S100 S120

DF24 DX38 DX50 DX70 DX84 DX110 DX140

93-10-010 93-10-020 93-10-030 93-10-040 93-10-050 93-10-060 93-10-080 93-10-100 93-10-120

20 MG 40 MG 60 MG 80 MG 100 MG 120 MG

30 x 30 40 x 40 60 x 60 80 x 80 100 x 100 120 x 120

SQUARE MESH Manufacturers' Reference Numbers**

0.028/0.020 0.014/0.014 0.013/0.013 0.013/0.009 0.009/0.009 0.0075/0.0075

2464/762 914/490 940/305 1041/193 406/193 457/140

46.6 41.8 35.6 34.0 29.4 35.6

36.7 14.0 9.1 8.6 4.5 4.4

8 x 20 (2464 x 762, 46.6%) 20 x 30 (914 x 490, 41.8%) 20 x 40 (940 x 305, 35.6%) 20 x 60 (1041 x 193, 34.0%) 40 x 60 (406 x 193, 29.4%) 40 x 80 (457 x 140, 35.6%)

191-25 191-26 191-28 191-30

B20 B40 B60 B80 B100 B120

R25 R30 R40 R600 R80

Thule (HS or PTS)

-

MBX 80 MBX 100 -

10 x 20 16 x 30 20 x 40 34 x 68 40 x 80

*

API designation is number of openings per inch in the flow direction, followed by the number of openings per inch in the direction perpendicular to the flow. This is followed by the opening size in microns in each direction and the percent open area.

**

Manufacturers' reference numbers are for nearest equivalent screen to that specified. When ordering screens, specify shaker model in addition to screen size and reference number.

TABLE 1 - SHAKER SCREEN CHARACTERISTICS (SINGLE MESH MARKET GRADE CLOTH - unless specified)

4600/GEN

8 x 20 20 x 30 20 x 40 20 x 60 40 x 60 40 x 80

SWACO

:

Derrick

Section

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Baroid

:

API Designation*

SWECO (backing cloth)

Rev.

Conductance kD/mm

6 of 11

Percent Open Area %

:

Opening Width microns

Page

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Wire Diameter inches

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Percent Open Area %

DRILLING MANUAL

Opening Width microns

SOLIDS CONTROL

Mesh

Wire Diameter inches

BP EXPLORATION

DRILLING MANUAL SUBJECT: xi)

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SOLIDS CONTROL Coarse mesh screens discharge drier cuttings than finer screens. This can influence screen choice when drilling with oil based mud and attempting to adhere to strict environmental regulations concerning oil retention on cuttings.

Sandtraps Sandtraps must never be bypassed and, when using water based mud, must be dumped regularly to prevent solids build-up. Sandtraps must not be dumped when using oil based mud.

2.4

2.5

Degassers i)

The vent line from the degasser should be run to the top of the derrick to ensure that expelled gases are vented away from the rig.

ii)

Degasser operation must be checked daily whilst drilling ahead.

iii)

The degasser must always be used when circulating bottoms up after tripping in hole, or if mud loggers report oil/gas shows in mud.

iv)

The degasser pit (if appointed as such) must remain separate from the normal circulating path to prevent solids settling.

v)

Several types of degasser are in service. The most common are the centrifugal degasser and the vacuum degasser. For detailed operational guidelines on specific degassers consult the manufacturer's operations manual.

Hydrocyclones The following guidelines apply to desanders, desilters and mud cleaners. i)

Hydrocyclone suction tanks must be permanently agitated to prevent solids settling. A screen over the suction inlet prevents large clumps of cuttings causing feed plugging of the cone inlets.

ii)

Each hydrocyclone unit should have its own pump assigned solely for its use, to maintain minimum feed head requirements.

iii)

The number of bends, swages and reducers in the lines feeding the header should be minimised. The header feed pipe should never have a horizontal bend connecting it to the header, and any other bend or restriction should be at least 3 pipe diameters in front of the header to ensure even presentation of mud flow to all cone inlets.

iv)

Optimum feed head requirements for cones is given by: Optimum Inlet Pressure (psi)

=

Optimum Feed head (ft) x Mud Weight (ppg) x 0.052.

Most cones have an optimum head of 75 ft (± 5 ft) so the ideal inlet pressure can be approximated to: v)

Hydrocyclone efficiency reduces dramatically if the feed head differs markedly from optimum. Centrifugal pumps feeding the hydrocyclone units have fixed discharge heads for a given impellor size, RPM and horsepower. However, since the centrifugal pump is usually situated some distance beneath the hydrocyclone inlet header, a change in mud weight will alter the hydrostatic and friction pressure losses in the feed pipe, and will cause a corresponding change in the feed head at the hydrocyclones. In such cases, the impellor size of the centrifugal pump should be changed so as to deliver mud at the optimum feed head to the cones.

vi)

Typical throughput capacities are as follows:

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SOLIDS CONTROL Desanders Desilters

12" cone - 500 gpm per cone 6" cone - 125 gpm per cone 4" cone - 50 gpm per cone 2" cone - 15 gpm per cone

So called "high capacity" cones (e.g. 4" cones rated for 80 gpm) have been found to produce significantly wetter discharge with no improvement in solids separation, and should not be used. vii)

Cones should be operated under spray discharge for maximum separation efficiency (see Figure 3). The causes of abnormal underflow discharge patterns, the effect upon cone wear and remedies to the problems are given in Table 2.

viii)

Hydrocyclone units must be stripped and cleaned prior to and after every period of continuous hole section operation.

ix)

Solid separation efficiency varies directly with the square root of the plastic viscosity of the mud: D50 ∝ √ PV As implied by Stoke's Law, when viscosity increases, solids settling viscosity decreases, hence D50 cut point increases.

Underflow

Cause

Wear Pattern

Remedy

Spray Discharge

-

Grooving over lower 2" of cone.

Correctly set up.

Rope Discharge

Overload of solids in feed and/or undersized cone apex (possibly caused by plugging).

Sharp grooving 1/3 way up cone and erosion of cone top due to solids in overflow.

Increase apex size until spray discharge is achieved, if unsuccessful remove cone and clean out underflow blockage.

Continuous Flow Discharge

Low inlet velocity as result of low feed head probably caused by partial or total plugging of feed header

Excessive wear at cone apex.

Strip and clean feed header and regulate pump to provide ± 75 ft head.

Plugged Discharge

Underflow plugging at cone apex caused by solids overload and/or restriction in underflow opening.

Sharp grooving 1/2 way up cone and erosion of cone top due to solids in overflow.

Disassemble cone, clean out blockage and reset apex size.

Table 2 - Hydrocyclone Troubleshooting Guide a)

Desanders i)

The primary use of desanders is in top hole sections when drilling with water based mud to help maintain low mud weights. Use of desanders prevents overload of the desilter cones and increases their efficiency by reducing the mud weight and solids content of the feed inlet. Desanders should be used if the sand content of the mud rises above 0.5% to prevent abrasion of pump liners.

ii)

Desanders must not be used with oil based muds.

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SOLIDS CONTROL FIGURE 3

HYDROCYCLONE OPERATION AIRCORE VORTEX

LIQUID DISCHARGE ( OVERFLOW ) VORTEX FINDER

SOLIDS REPORTING TO OVERFLOW

( 2 ) SLURRY ROTATION DEVELOPS HIGH CENTRIFUGAL FORCES THROUGHOUT CYCLONE

( 1 ) PRESSURIZED SLURRY ENTERS TANGENTIALLY

WORKING ( INSIDE ) DIAMETER OF CONE

( 4 ) LIQUID MOVES INWARDS AND UPWARDS AS SPIRALLING VORTEX

ZONE MAXIMUM WEAR

( 3 ) SUSPENDED SOLIDS DRIVEN TOWARDS WELL AND DOWNWARD IN ACCELERATING SPIRAL

'DEAD' AREA NO ROTATION NO CONE WEAR ADJUSTABLE APEX

RAPID CONE WEAR CONCENTRATED IN THIS AREA

SLOW 'FALLING' DISCHARGE

SOLIDS DISCHARGE ( UNDERFLOW )

AIR SUCTION ( a ) SPRAY DISCHARGE ( SYSTEM OPERATING EFFICIENTLY )

NO AIR SUCTION ( b ) ROPE DISCHARGE ( INEFFICIENT SOLIDS SEPARATION )

2179/75

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iii)

b)

Section

Despite manufacturers' claims, the D50 cut point of most 12" cone desanders is in the range 200 - 220 microns for an unweighted water based mud. As such the use of desanders is ineffective when the shakers are dressed with 80 mesh screens or finer.

Desilters i)

Desilter cones must be periodically "balanced" to give the correct spray discharge for efficient solids separation. To achieve the correct apex settings, operate the desilter on clean water. With all apexes fully open, there should be a thin curtain-like spray of water from each cone. Close each apex slightly until only a slow drop of water occurs. Avoid over-adjusting, as this will cause plugging when the cones operate on mud.

ii)

Desilters, in conjunction with desanders, should be used in low weight mud top hole sections. If it is required to raise mud weight, this must be done by barite addition and not by allowing a build-up of low gravity solids.

iii)

Desilters must not be used with oil based muds.

iv)

Despite manufacturers' claims, the D50 cut point of most 4" cones is in the range 60 - 80 microns for an unweighted water based mud. With weighted oil based mud the D50 cut point is very much higher (greater than 200 microns) and the solids discharge far wetter. Hence desilters should not be used with oil based mud.

Mud Cleaners i)

Mud cleaners must only be used when it becomes impossible to maintain low mud weights by use of shale shakers alone. It is far more efficient to use desilters and to process the underflow with a centrifuge than to use a mud cleaner. If the shakers are dressed with very fine screens (120 mesh or finer), the use of a mud cleaner is almost totally ineffective.

ii)

The use of mud cleaners with oil based mud should be minimised since experience shows mud losses of 3 - 5 bbls/hr in the discharge are not uncommon, coupled with the necessity to adhere to strict environmental pollution regulations.

iii)

Mud cleaners were originally designed to remove larger drilled solids from weighted muds but to return barite from the screen underflow to the active mud. The great disadvantage of mud cleaners is that silt sized drilled solids (sub 74 micron) discarded by the cones are also returned back to the mud system, leading to poor particle size distribution, adversely affecting mud properties and drilling performance. Economic factors now dictate that it is more costly to treat the effects of retaining low gravity fines in the mud than to discard barite from the cone underflow.

Centrifuges i)

Centrifuge efficiency is affected predominantly by the feed flowrate but is also influenced by the following operating adjustments in decreasing order of importance: a) Bowl speed (rpm). b) Bowl/conveyor differential speed (rpm). c) Pool depth.

ii)

The operating efficiency is highly sensitive to mud viscosity (hence temperature for oil based muds), the higher the viscosity the higher the D50 cut point. The feed flowrate capacity reduces significantly as mud weight is increased, a density increase also causes the gear box torque to rise and fluctuate in an unstable fashion.

iii)

Only positive displacement (mono type) pumps should be used to feed the centrifuge with adjustable flowrates in the range 15 - 150 bbls/hr.

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iv)

The centrifuge must be fitted with a mechanical torque sensor coupled with an overload protection device. This should automatically shut down the main centrifuge motor and the feed pump when tripped by conditions of excessive torque.

v)

There are two methods of centrifuge operation, either the underflow or the overflow discharge may be discarded. When dealing with low weight mud the solids underflow is discarded as a means of solids control to obtain desirable particle size distribution and reduce mud weight. Processing capacity of the centrifuge may limit its use for this purpose to lower hole sections where circulation rates are lower. It can also be used to process the underflow from desilters, returning an expensive or environmentally harmful liquid phase to the active mud system, and discarding relatively dry solid fines. With weighted muds, the solids underflow containing barite may be returned to the mud system and the liquid phase containing viscosity building colloids discharged. However, it is unlikely to be used for this purpose with oil based muds for both economic and environmental reasons.

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POLICY There are no BP policies on drilling hydraulics.

2.

HYDRAULICS PLANNING The circulating mud system fulfills 3 major hydraulic functions: •

Maintains well control without exceeding fracture gradient.

•

Provides adequate hole cleaning.

•

Provides hydraulic energy to keep the bit face clean.

The above 3 functions are interrelated and in practice cannot all be optimised simultaneously. Generally some form of compromise is necessary, although naturally well control remains of paramount concern. In practice factors such as: hole angle, hole size, fracture gradient, formation hardness and anticipated penetration rate will all influence the route for optimum hydraulics. There is no point in designing optimum hydraulics for maximum energy at the bit if the hole cannot be adequately cleaned. Similarly it is wasteful to provide a higher flowrate than necessary, and increase the risk of hole erosion. The overall strategy for developing an optimised hydraulic plan is outlined in Figure 1. The hydraulics on a well need to be individually assessed for each bit run. The following section of the Manual provides the means to achieve this. 3.

MUD RHEOLOGY

3.1

Rheological Measurement Viscosity of the drilling fluid is determined by 2 rig site methods: a)

Marsh Funnel - This is a quick test which indicates a relative change in fluid viscosity since the previous measurement. It gives no meaningful value other than this, and should never be totally relied upon for maintaining the quality of fluid in circulation.

b)

Rotational Viscometer (Fann VG Meter) - The mud sample is sheared over a range of speeds between a rotating outer sleeve and an inner stationary bob. The torque measured on the inner bob is a measure of the fluid viscosity. Measurements are made at six discrete speeds (600, 300, 200, 100, 6 and 3 rpm) which correspond to shear rates in the range 5 - 1022 s-1. The procedure for using the rotational viscometer is given in Section 4500/GEN.

Data from the Fann viscometer are converted to a shear stress vs. shear rate diagram (rheogram) by multiplying by the appropriate instrument constants viz: Shear Stress

:

τ (lb/100 ft2) = θ x 1.067

Shear Rate

:

γ (s-1) = rpm x 1.703

An example rheogram is illustrated in Figure 2. 3.2

Fluid Models There is a wide choice of rheological models which describe the non-Newtonian behaviour of drilling muds. Traditionally, however, because these models are needed to calculate circulating system

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pressure losses, only the simplest models have been used in practice. With the advent of readily available computing power, this restriction is becoming less severe. For the purposes of “hand calculations”, the most commonly used rheological models are the Bingham Plastic and Power Law. These are both 2-parameter models. BP’s Toolkit hydraulics program uses a 3-parameter model referred to as the Modified Power Law or Generalised Bingham. Pressure drops calculated by the Bingham Model will tend to be higher than those calculated using the Power Law, with the Generalised Power Law giving values intermediate. 3.2.1

Bingham Plastic Model A Bingham Plastic fluid is characterised by a non-zero intercept on the shear stress axis referred to as the yield point (YP). Beyond the YP the relationship between the shear stress and shear rate is linear. The slope of this line is the plastic viscosity (PV). The equation relating shear stress and shear rate is: τ

= YP + PV γ

The geometry and spring constant of the Fann viscometer has been designed so that: PV

=

θ

600

- θ

YP

=

θ

300

- PV

300

cP lb/100 ft2

PV is a measure of the base fluid viscosity and the flow resistance due to mud solids; YP is a measure of the interactive forces within the flowing system. 3.2.2

Power Law Model In a Power Law fluid the shear stress and shear rate are related by a non-linear function which goes through the origin and falls off as the shear rate is increased. Such fluids are said to be shear thinning or pseudoplastic. Their viscosity decreases as the shear rate increases. The relationship between shear stress and shear rate for a Power Law fluid is: τ

=

kγ

n

The values of n (power law index) and k (consistency index) are calculated from the Fann as follows: n

k

=

=

1.44 ln θ θ θ 300 (511)n

600

(Dimensionless)

300

(lb sn/100 ft2)

Small values of “n” indicate that a fluid is highly shear thinning. The k factor is a measure of the fluid viscosity at low shear rate. The value of k can be raised by the addition of viscosifiers or reduced by dilution. 3.2.3

Modified Power Law This model represents hybrid behaviour of the Bingham and Power Law. The fluid exhibits non-linear shear stress/shear rate behaviour, together with a yield point. Mathematically the relationship between shear stress and shear rate is expressed:

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τ

=

τ

o

+ k γ

n

Because this is a 3-parameter model, a minimum of 3 Fann readings are required to establish the model parameters. The standard rig-site procedure is to set τ o equal to the Fann 3 rpm reading, and then perform the conventional power law calculations viz: τ

o

n

k

=

θ

=

1.44 ln (θ (θ

=

θ

(lb/100 ft2)

3

- θ (511)n 300

600 300

- θ 3) - θ 3)

3

(Dimensionless) (lb sn/100 ft2)

The flow curves for each of the fluid models are shown in Figure 3. 4.

PRESSURE LOSSES IN THE CIRCULATING SYSTEM

4.1

Flow Regimes The pressure drop relationships for flow through pipes and annuli vary depending upon whether the flow is laminar or turbulent. In laminar flow the fluid streamlines are very ordered and the pressure drop depends strongly upon the viscous properties. In contrast, turbulent flow is chaotic, with pressure drop influenced by inertial forces (i.e. flowrate and density) rather than viscosity. The flow regime is determined by the Reynolds Number (Re). This dimensionless quantity is a measure of the ratio of inertial to viscous forces and is defined (for a Newtonian fluid in pipe flow) as: – Re = V d W (Dimensionless) µ (Descriptions for non-Newtonian fluids differ because of the viscosity term. However, corresponding expressions for non-Newtonian fluids in pipes/annuli do exist and so the principles are still the same.) Change from laminar flow to turbulent flow begins at Re ~ 2100 and passes through a transition zone prior to full turbulence. For the purposes of the hydraulic calculations, it has been assumed that the laminar/turbulent transition occurs at Re = 3000. The normal flow regimes for the various parts of the drilling fluid circulation system are given in the table below: Surface Hose Drill Pipe Drill Collars Bit Nozzles Annulus

4.2

-

Turbulent Transitional or Turbulent Turbulent Turbulent Laminar or Transitional

Pressure Drop Distribution Since the returning mud at the flowline is at atmospheric pressure, the discharge pressure delivered by the pump has been totally dissipated throughout the system. The pressure drops may be denoted by: a)

PSURF

-

the pressure loss in the surface connections (e.g. standpipe, kelly hose, etc.). This is generally small in comparison to other components (< 100 psi).

b)

PDS

-

the pressure loss in the drillstring (i.e. inside the drill pipe and BHA).

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c)

PB

-

the pressure loss through the bit nozzles. This is where most of the pressure drop should occur for efficient drilling.

d)

PA

-

the pressure drop in the annulus.

Therefore Total Pressure Drop (PT) is: PT

=

PSURF + PDS + PB + PA

Typically in the complete circulating system, the distribution of pressure drops is as follows: Surface Hose Drill Pipe Bit Nozzles Annulus

3 - 5% 30 - 40% 50 - 65% 5 - 10%

In deeper sections of the well, the system pressure loss should be controlled so that most of the total pressure delivered by the pump is used across the bit. In upper hole sections, the bit pressure loss is less critical and should be minimised to allow maximum flowrate for hole cleaning (see Section 5). 4.3

Pressure Drop Calculations The following section contains simple pressure drop calculations which can be done using a hand-held calculator. These calculations should provide a good estimate of the overall pressure drop and how the pressure is distributed. Generally the Bingham model will give higher pressure losses than the Power Law model. The equations for the Generalised Power Law model have not been included since they are not readily solved using a hand-held calculator. These equations can be accessed through BP’s Drilling Engineers Toolkit. Predictions from the Generalised Power Law model generally lie between the Bingham and Power Law extremes. Experience has shown that pressure losses in oil based muds for shallow wells (< 3000m) are some 15 - 20% higher than in equivalent water based systems. The following hydraulic equations can be used for estimating total system pressure losses at the planning stage of a well. At the rig site, the equations should be used to determine the additional system loss which will occur as drilling progresses and more drillpipe is added to the string.

4.3.1

Surface System Pressure Losses The following table gives the surface system pressure coefficients for the standard API designations. Case

Standpipe

Hose

Swivel

Kelly

C

1 2 3 4

40’ x 3” 40’ x 3 1/2” 45’ x 4” 45’ x 4”

45’ x 2” 55’ x 2 1/2” 55’ x 2 1/2” 55’ x 3”

4’ x 2” 5’ x 2 1/2” 5’ x 2 1/2” 6’ x 3”

40’ x 2 1/4” 40’ x 3 1/4” 40’ x 3 1/4” 40’ x 4”

1.0 0.36 0.22 0.15

PSURF

=

PSURF (psi);

C x W

1.86

( 32Q )

W (SG);

Q (gpm).

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For rigs with top drive and platforms with lengthy surface pipework, the coefficient C needs to be determined on site. This requires subtracting the spp from the pump pressure reading at a known flowrate. EXAMPLE For a Case 4 type surface system, circulating at 650 gpm with 1.44 SG mud, the following pressure loss can be expected: PSURF

=

0.15 x 1.44 x

=

58 psi

1.86

(650 32 )

(PSURF is measured at the standpipe gauge; there will be an additional pressure drop in the lines from the mud pumps.) 4.3.2

Pipe Flow The effect of tool joints should be taken into account when calculating PDS. This can be done by summating all the tool joint lengths in the string and calculating the pressure drop through this smaller ID for that length. BINGHAM PLASTIC MODEL 1.

2.

Determine Average Velocity: – V = 24.5Q d2 Determine Critical Velocity (Re = 3000): Vc

3.

=

11.65 PV + 11.65 {(PV)2 + 68.3 W d2 YP}1/2 Wd

(ft/min)

– If V > Vc, Flow is turbulent; use: Pd

4.

(ft/min)

=

1.594 x 10-3 W0.8 Q1.8 (PV)0.2 L d4.8

– If V < Vc, Flow is laminar; use: – Pd = L PV V + L YP 27,400 d2 69 d

(psi)

(psi)

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POWER LAW MODEL 1.

Determine n and k: θ 600 θ 300

= =

n

1.44 ln

=

2 PV + YP PV + YP

(θθ )

(Dimensionless)

600

300

k

2.

(ft/min)

=

3

n (2-n)

1 (2-n)

( 6.99 xW10 K )

( 1.6d

•

3n + 1 4n

)

(ft/min)

=

1.594 x 10-3 W0.8 Q1.8 (PV)0.2 L d4.8

(psi)

– If V < Vc, Flow is laminar; use:

Pd

4.3.3

24.5Q d2


5.

=

Determine Critical Velocity (Re = 3000):

Vc

4.

(lb sn/100 ft2)

Determine Average Velocity: – V

3.

θ 300 (511)n

=

=

(

– 1.6 V d

(3n + 1 ) n 4n

)

•

K L 91.4d

(psi)

Annular Flow BINGHAM PLASTIC MODEL 1.

2.

Determine Average Velocity: – V = 24.5 Q (dh2 - dp2)

(ft/min)

Determine Critical Velocity (Re = 3000): Vc

=

14.3 PV + 14.3 {(PV)2 + 42.5 W (dh - dp)2 YP}1/2 W (dh - dp)

(ft/min)

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4.

Section

=

1.594 x 10-3 W0.8 Q1.8 (PV)0.2 L (dh - dp)3 (dh + dp)1.8

– If V < Vc, Flow is laminar; use: – Pd = L PV V + 18300 (dh - dp)2

(psi)

(psi)

L YP 61 (dh - dp)

POWER LAW MODEL 1.

2.

Determine Average Velocity: – V = 24.5 Q (dh2 - dp2) Determine Critical Velocity (Re = 3000):

Vc

3.

3

( 5.70 xW10 K )

( (dh 2.4- dp) ( 2n3n+ 1 ))

•

(ft/min)

=

1.594 x 10-3 W0.8 Q1.8 (PV)0.2 L (dh - dp)3 (dh + dp)1.8

(psi)

– If V < Vc, Flow is laminar; use: Pd

4.3.4

=

n (2-n)

1 (2-n)


4.

(ft/min)

=

(

– 2.4 V (2n + 1 ) n (dh - dp) 3n

)

K L 91.4 (dh - dp)

(psi)

Pressure Drop Across Bit 1.

Pbit

=

Pstandpipe - (Psurf + Pds + PA)

=

W Q2 1303 An2

or 2.

Pbit

(psi)

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Nozzle Velocity: =

11.6

1/2

( PW ) bit

(ft/sec)

Total Area of Nozzles: An

4.4

:

DRILLING HYDRAULICS

Vn

4.

Section

=

(ins2)

0.32 Q Vn

Use of Flow Equations Example: Pressure Loss for Bingham Plastic Model A deviated 12 1/4” hole section is being drilled which requires a minimum flowrate of 700 gpm to provide adequate hole cleaning. Using the Bingham Model determine the pressure drops throughout the system and hence the smallest bit nozzles which can be run without exceeding the maximum surface pressure. Mud Properties: Plastic Viscosity (PV) Yield Point (YP) Weight (W)

= = =

31 cP 27 lb/100 ft2 1.38 SG

Flowrate (Q) 5” Drill Pipe ID

= =

700 gpm 4.276 in

Length of 5” DP (L) at programmed end of bit run

=

1975m

8” Drill Collars ID Length of 8” DC (L)

= =

2.875 in 189m

13 3/8” Casing ID 13 3/8” Shoe at

= =

12.565 in 777m

2 Pumps operating at Max. Standpipe Pressure

=

3000 psi

Surface Equipment Type

=

4

Drilling Parameters:

Using the Bingham Plastic Model A.

Surface Losses PSURF

PSURF

1.86

( 32Q )

=

CW

=

0.15 x 1.38

=

64 psi

1.86

( ) 700 32

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Pipe Losses i)

Inside Drillpipe – Average Velocity V

Critical Velocity Vc

=

24.5 x 700 (4.276)2

=

24.5Q d2

=

938 ft/min

=

11.65 PV + 11.65 {(PV)2 + 68.3 W d2 YP}1/2 Wd

=

11.65 x 31 + 11.65 {(31)2 + 68.3 x 1.38 x (4.276)2 x 27}1/2 1.38 x 4.276

=

491 ft/min

– Since V > Vc, flow is TURBULENT, ∴ Pd

ii)

=

1.594 x 10-3 W0.8 Q1.8 (PV)0.2 L d4.8

=

1.594 x 10-3 x (1.38)0.8 x (700)1.8 x (31)0.2 x 1975 (4.276)4.8

=

1001 psi

Inside Drill Collars – Average Velocity V

Critical Velocity Vc

=

24.5 x 700 (2.875)2

=

2075 ft/min

=

11.65 x 31 + 11.65 {(31)2 + 68.3 x 1.38 x (2.875)2 x 27}1/2 1.38 x 2.875

=

527 ft/min

– Since V > Vc, flow is TURBULENT, ∴ Pd

=

1.594 x 10-3 x (1.38)0.8 x (700)1.8 x (31)0.2 x 189 (2.875)4.8

=

644 psi

Hence total pressure loss in drill string: PDS = 1645 psi.

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C. Annular Losses Pressure Losses Around 5" Drillpipe i)

Cased Hole Section – V = 24.5 x 700 (12.565)2 - (5)2 Vc

=

129 ft/min

=

14.3 x 31 + 14.3 {(31)2 + 42.5 x (12.565 - 5)2 x 1.38 x 27}1/2 1.38 x (12.565 - 5)

=

457 ft/min

– Since V < Vc, flow is LAMINAR, ∴ Pd

ii)

=

– L . PV . V 18300 (dh - dp)2

=

777 x 31 x 129 18300 (12.565 - 5)2

=

47 psi

Open Hole Section – V = 24.5 x 700 (12.25)2 - (5)2 Vc

+

=

L YP 61 (dh - dp) +

777 x 27 61 (12.565 - 5)

137 ft/min

=

14.3 x 31 + 14.3 {(31)2 + 42.5 x (12.25 - 5)2 x 1.38 x 27}1/2 1.38 x (12.25 - 5)

=

459 ft/min


=

1198 x 31 x 137 18300 (12.25 - 5)2

=

78 psi

+

1198 x 27 61 (12.25 - 5)

Therefore Total Pressure Loss Around Drillpipe is: 47 + 78 = 125 psi.

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DRILLING HYDRAULICS Pressure Loss Around 8" Drill Collars – V = 24.5 x 700 = 200 ft/min (12.25)2 - (8)2 Vc

=

14.3 x 31 + 14.3 {(31)2 + 42.5 x (1.38) x (12.25 - 8)2 x 27}1/2 1.38 x (12.25 - 8)

=

495 ft/min


=

189 x 31 x 200 18300 (12.25 - 8)2

=

23 psi

+

189 x 27 61 (12.25 - 8)

Therefore Total Annular Losses PA = 125 + 23 = 148 psi. D. Pressure Drop Across Bit

E.

Since

PT

=

PSURF + PDS + PA + PB = 3000 psi

∴

PB

=

3000 - (64 + 1645 + 148)

=

3000 - 1857

=

1143 psi

Nozzle Velocity Vn

=

=

F.

B

1/2

Total Area of Nozzles: An

1/2

( PW ) 11.6 1143 ( 1.38 ) 11.6

=

0.32 Q Vn

=

0.32 x 700 334

=

0.670 in2

=

334 ft/s

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Nozzle Sizing (in 1/32 nd)

1/2

( )

=

32

=

17.08

4An 3π

Hence 3 x 17 nozzles can be selected to remain within the surface pressure limitations. Note that for an OBM where the frictional pressure drop is assumed to be 20% higher, the allowable PB = 3000 (1857 x 1.2) = 772 psi. In this case 2 x 18 and 1 x 20 nozzles would be required. 4.5

Pump Performance Characteristics Pump Discharge Pressure (psi) Pump Discharge Volume (gal/stroke) (based on 90% Mechanical and 100% Volumetric Efficiency)

Manufacturer: NATIONAL SUPPLY - Triplex

Model

Rated Rated Stroke IHP SPM Length

8-P-80

800

Liner Size (in) 4 1/2 4 3/4 5

5 1/4

4395 3945 3560 3230 1.8 2.0 2.2 2.4

5 1/2 5 3/4 6

6 1/4 6 1/2

6 3/4 7

7 1/4

2940 2690 2470 2280 2.6 2.9 3.1 3.4 -

-

-

-

160

8 1/2

10-P-130 1300

140

10

5000 2.5

4645 4250 3900 3595 3325 3.1 3.4 3.7 4.0 4.3

3085 4.6 -

12-P-160 1600

120

12

-

5000 5000 4670 4305 3980 3.7 4.0 4.4 4.8 5.2

3690 3430 3200 5.6 6.0 6.4

Manufacturer: OIL WELL - Triplex Liner Size (in)

Model

Rated Rated Stroke IHP SPM Length

HD 1400 PT

1400

120

12

5000 4861 3.06 3.7

A1400-PT

1400

150

10

A1700-PT

1700

150

12

5

6 1/2 6 3/4

7

3481 5.2

3001 6.0

5000 4723 4321 3968 2.6 3.1 3.4 3.7

3381 3135 4.3 4.6

2915 2718 2540 5.0 5.4 5.7

5000 4723 4321 3968 3.1 3.7 4.0 4.4

3381 3135 5.2 5.6

2915 2718 2540 6.0 6.4 6.9

5.

HOLE CLEANING

5.1

How Cuttings are Transported

5 1/2 5 3/4 6 4085 4.4

7 1/4 7 1/2 2614 6.9

Figure 4 is a schematic representation of the transport mechanism for a range of well inclinations. In holes inclined less than 30 degrees, the cuttings are effectively suspended by the fluid shear and beds do not form (Zones 1 and 3). Beyond 30 degrees the cuttings form beds on the low side of the hole which can slide back down the well, causing the annulus to pack-off. These cuttings have been observed to be transported out of the well by a combination of two different mechanisms. Cuttings which form on the low side of the hole can either slide as a block (Zone 4), or alternatively may be

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transported at the bed/mud interface as ripples or dunes (Zone 2). This latter transport mechanism, referred to as saltation, is best induced by low viscosity fluids pumped in turbulence (high flowrate). The ideal zones for good hole cleaning are 1 and 2, whereas Zone 5 is virtually a guarantee of tight hole problems. 5.2

Influence of Drilling Variables on Hole Cleaning

HOLE ANGLE: Generally as hole angle increases, cuttings removal becomes more difficult. Angles between 50 - 60 degrees present most problems because of the tendency of the cuttings to slide down the annulus and cause packing off. In wells deviated beyond 60 degrees, the cuttings form stable beds which are supported by the sliding friction against the wellbore. ROP: Increases in penetration rate result in higher cuttings concentrations in the annulus. For vertical and near vertical wells, experience has shown that the maximum allowable annular concentration for efficient drilling is 5%. For deviated wells, increases in penetration rate correspond to deeper cuttings beds. These deeper beds require higher flowrates to remove. In deviated holes, it is important to control and limit instantaneous ROP’s since deep beds are difficult to remove. MUD RHEOLOGY: Mud viscosity affects cuttings slip velocity and so has a large influence on transport efficiency in vertical and near-vertical wells. However, once cuttings beds form (> 30 degrees), changes in conventional mud rheology have little benefit. At angles above 30 degrees, low viscosity fluids are most effective since they induce turbulence and encourage cuttings removal by saltation. PUMP RATE: Mud flow is the single most crucial factor for successful hole cleaning. This is particularly true for deviated holes. As a rough guide, the annular velocity needed for cleaning wells deviated 50 - 60 degrees, is approximately twice that required for the vertical case. All reasonable steps must be taken to ensure frictional pressure losses are reduced, thus extending the range of available flowrate. In critical cases careful consideration should be given to BHA design, nozzle selection and additional losses due to mud motors/MWD tools (see Section 7). The use of 6 5/8” drillpipe significantly reduces pressure drop, thus allowing higher flows to be achieved. MUD WEIGHT: Mud weight influences hole cleaning by affecting the buoyancy of the drilled cuttings. This is true both for vertical and deviated holes. For small changes in density, the flowrate required to maintain adequate hole cleaning is directly proportional to the cuttings-mud density differential. CUTTINGS TYPE: Formation density will affect hole cleaning in the same way as changes in mud weight. For both vertical and inclined wells, increases in cuttings density make hole cleaning more difficult. Cuttings shape and size play an important role in vertical transport - the larger more rounded particles being the hardest to remove. In highly deviated wells, shape and size have little influence because the cuttings move in blocks rather than discrete particles. DRILLPIPE ROTATION: Rotation of the drill string will assist in mechanically disturbing cuttings beds in deviated wells. The action of the rotating pipe forces cuttings upwards to the high side of the hole and into the fast moving mud stream. In addition, rotation of the drillpipe will encourage mud flow in the narrow gap between the pipe and the settled bed. When a downhole motor is used in a deviated well, it is probable that the cuttings beds are not being disturbed. Rotation of the string prior to tripping should be considered. 5.3

Hole Cleaning Calculations

5.3.1

Vertical Holes The calculation for vertical holes is based on a maximum allowable cuttings concentration of 5% in the annulus. This concentration is related to the cuttings generation rate (ROP); mud flowrate and cuttings slip velocity. For simplicity, the equations have been converted into graphical form which can be used to determine the optimum flowrate for hole cleaning.

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PROCEDURE 1.

Enter Figure 5(a). Draw line from mud YP through cuttings size to intersect left hand projection line (Point A).

2.

Draw line from Point A through hole diameter to intersect right hand projection line at Point B.

3.

Draw line from Point B to mud PV. Read off Effective Viscosity (cP) at the crossover point.

4.

Enter Figure 5(b). Draw line from Effective Viscosity through mud SG to intersect left hand projection line (Point C).

5.

Draw line from cuttings SG through mud SG to intersect right hand projection line at Point D.

6.

Join line from Point C to Point D. Read off cuttings slip velocity (Vs) for the appropriate cuttings size.

7.

Enter Figure 6 at appropriate hole size. Draw line from cuttings slip velocity through pivot point to cross penetration rate lines.

8.

For appropriate ROP, read off minimum annular velocity required.

EXAMPLE 1 17 1/2” vertical hole: PV YP SG

: : :

40 cP 20 lb/100 ft2 1.4

Cuttings SG : 2.5 Cuttings Size : 1/2” Determine annular velocity required to clean hole at penetration rate of 30 m/h.

5.3.2

1.

Using Figure 5(a) - Effective Viscosity - 140 cP.

2.

Using Figure 5(b) - Settling Velocity = 45 ft/min.

3.

Using Figure 6(a) - Annular Velocity @ 30 m/h = 82 ft/min.

Low Angle Wells (< 30 degrees) Wells inclined between 0 and 30 degrees require higher flowrates than the corresponding straight holes. The recommended procedure is based on the same criteria as vertical holes, except the cuttings slip velocity is modified to allow for the increased angle (1% increase per degree of inclination). PROCEDURE 1. - 6. Follow procedure for vertical holes in 5.3.1 above. 7.

Calculate Effective Slip Velocity = Vs * (1 + Inclination/100).

8.

Enter Figure 6 and draw line from effective slip velocity through pivot point to intersect penetration rate lines.

9.

For appropriate ROP read off annular velocity required.

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EXAMPLE 2 Using same data for Example 1 above, what annular velocity is required to clean the hole if the angle is increased to 20 degrees?

5.3.3

a)

Using Figure 5(a) - Effective Viscosity = 140 cP.

b)

Using Figure 5(b) - Slip Velocity = 45 ft/min.

c)

Effective Slip Velocity = Vs * 1.2 = 54 ft/min.

d)

Using Figure 6(a) - Annular Velocity at 30 m/h = 94 ft/min.

High Angle Wells (> 30 degrees) The recommended model for angles above 30 degrees assumes that all the cuttings generated at the bit instantaneously fall to the low side of the hole and form a bed. It is then assumed that cuttings will only be removed when the driving force exerted by the circulating mud exceeds the frictional resistance force of the cuttings against the open hole. The model does not take account of drillpipe rotation nor does it allow for supplementary transport by particle saltation. Both of these mechanisms will improve hole cleaning. The model should therefore overestimate the necessary flowrate and so err on the conservative side. PROCEDURE 1.

Use mud logger to determine cuttings bulk density (Cuttings SG).

2.

Enter right hand Figure 7 and read off effective mud SG (ESG) from known cuttings density and mud weight.

3.

Calculate the mud Transport Index from: Transport Index

=

Q (gpm) * ESG 100

4.

Enter left hand graph at appropriate Transport Index and hole angle and read off the maximum allowable ROP for the set flowrate.

5.

To calculate the required flowrate for a known ROP, the above procedure is followed in reverse.

EXAMPLE 3 17 1/2” hole at 40 degrees to be drilled with conventional 5” drillpipe. Mud weight is 1.4 SG and cuttings density 2.3 SG. What is the maximum safe ROP at a flowrate of 950 gpm? a)

Use Figure 7(a). Enter right hand graph at mud weight 1.4 SG, cuttings SG 2.3 and read effective mud density (ESG) from the family of diagonal lines. ESG = 1.32.

b)

Calculate the Transport Index at 950 gpm: Transport Index

=

Q (gpm) * ESG 100

=

950 * 1.32 100

=

12.5

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Enter left hand graph at Transport Index = 12.5 and read off maximum ROP for hole angle of 40 degrees. Maximum ROP = 23 m/h.

EXAMPLE 4 For the same conditions above, conventional drillpipe is replaced by 6 5/8” dp. What is the maximum ROP if: a) b)

Flowrate is maintained at 950 gpm. Flowrate is increased to 1100 gpm.

1)

Determine ESG as above.

2)

The hole cleaning charts printed are for conventional 5” dp. Therefore, the Transport Index needs to be modified to allow for effective increased annular velocity. This is done by calculating the annular area ratio (AAR).

3)

For 17 1/2” hole and 6 5/8” pipe, the ratio of annular area is: AAR

4)

=

(17.52 - 6 5/82) (17.52 - 52)

=

1.07

At 950 gpm the effective Transport Index with 6 5/8” dp is: Transport Index

=

Q (gpm) * AAR * ESG 100

=

13.4

=

950 x 1.07 x 1.32 100

=

1100 x 1.07 x 1.32 100

At 1100 gpm the effective Transport Index is: Transport Index

5)

=

Q (gpm) * AAR * ESG 100

=

15.5

From the left hand Figure 7(b) the maximum allowable ROP’s at 40 degrees are: a)

30 m/h @ 950 gpm.

b)

40 m/h @ 1100 gpm.

(N.B. The upper limit of 40 m/h in 17 1/2” hole has been imposed to prevent unacceptably high cuttings loading in the annulus.) 5.3.4

Cuttings Transport in Riser When drilling from a semi-submersible, it is important that the annular velocity in the riser is sufficient to carry the cuttings out of the well. In practice this is generally only a problem for 8 1/2” hole sections and below, where flowrates fall below 400 gpm. PROCEDURE 1.

Use Figure 5 to determine cutting slip velocity.

2.

Compare Vs with annular velocity in riser.

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If Vs exceeds riser velocity then either increase mud YP to reduce Vs, or consider using a riser booster pump.

5.4

Supplementing Hole Cleaning

5.4.1

Cuttings Bed Suppression The formation of cuttings beds in deviated holes can be suppressed by using muds with exceptionally good suspension characteristics. High flows are however still necessary since the beds can never be totally eliminated. For water based mud the best conventional additive for this purpose is XC polymer. With oil muds all the major service companies offer low shear enhancers (sometimes referred to as rheology modifiers). A simple force balance approach can be used to determine the minimum mud rheology necessary to maintain drilled cuttings in suspension: 2 * θ

3

- θ

6

=

110 * (Cuttings SG - Mud SG) * Dp

where: θ

6

=

Fann 6 rpm reading.

θ

3

=

Fann 3 rpm reading.

Dp

=

Cuttings diameter (in).

For example, a 1.4 SG mud, with Fann 6/3 readings of 21/20 lb/100 ft2, will support a 1/4” cuttings with an SG of 2.1. 5.4.2

Fluid Pills For wells deviated below 30°, the use of conventional high viscosity/high weight slugs will assist in removing cuttings from the annulus. For wells deviated above 30°, viscous pills will have limited if no effect on hole cleaning. This will become more pronounced as the hole angle increases. Low viscosity pills or low viscosity followed by high density pills are NOT TO BE USED to assist hole cleaning. Use of these pill types has in the past resulted in hole pack-off due to a cuttings bed slump.

5.4.3

Circulation Prior to Tripping The minimum “on-bottom” circulation time prior to tripping will be influenced by hole size and inclination. The figures in the table below are guidelines based on simple slip velocity considerations and field experience.

Section Length Factor

Well Inclination Range 0° - 10° 10° - 30° 30° - 60° 60° +

17 1/2” Hole

12 1/4” Hole

8 1/2” Hole

1.5 1.7 2.5 3.0

1.3 1.4 1.8 2.0

1.3 1.4 1.6 1.7

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Since in practice not all of the section back to surface will be deviated at the same angle, the overall minimum circulation time prior to tripping should be apportioned in direct relation to the relative lengths of section at each angle. This is illustrated in Figure 8 for tripping out of 17 1/2” hole at 2350m. Mud circulation significantly in excess of the above guidelines is unlikely to have any real benefit. If cuttings beds have formed in the deviated sections and have not been removed by circulation while drilling, then these will only be removed by a combination of pills and mechanical methods (e.g. pumping out of the hole). 5.5

Summary of Recommended Hole Cleaning Practices

5.5.1

Drilling

5.5.2

•

Higher flowrates required for deviated wells (use method in 5.3.3).

•

Design BHA’s for minimum pressure loss in critical wells (see 4.3).

•

Hole angles 50° - 60° are most difficult to clean (see 5.3.3).

•

Control instantaneous ROP’s (use method in 5.3.3).

•

Use increased flowrate rather than changes in rheology for cleaning deviated wells (see 5.3.3 and 5.4.1).

•

Increased mud weight assists cuttings removal (see 5.3.3).

•

Drillpipe rotation assists hole cleaning in deviated holes. A minimum of 60 rpm is recommended. Higher rpm’s assist.

•

Minimise hole washouts by good hydraulic design (see 6.3).

•

Drill minimum rat hole consistent with safe running of casing.

•

If necessary use a riser booster pump on semi-submersibles (see 5.3.4).

Tripping •

Always circulate the hole clean prior to tripping. Use minimum circulation times given in 5.4.3.

•

Rotate the pipe at maximum of 60 rpm when circulating prior to tripping.

•

Use low vis/high wt pills for wells > 30°. Volumes to be calculated using method in 5.4.2.

•

Make a rotary wiper trip after long section drilled with downhole motor.

6.

BIT HYDRAULICS OPTIMISATION

6.1

Optimisation Methods The design of an efficient hydraulics programme is an important element in planning and drilling a well. Bit hydraulic optimisation involves making best use of the power developed by the mud pumps and ensuring that the bottom of the hole is cleaned effectively. This is particularly important for deep hard rock sections where wasteful regrinding of cuttings will severely limit ROP. The most commonly used methods of optimising drilling hydraulics and hence penetration rates are firstly maximising bit hydraulic horsepower (HHP) and secondly maximising bit hydraulic impact force (HIF). Maximising hydraulic horsepower assumes that the best method of cleaning the hole is to

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concentrate as much fluid energy as possible at the bit. Hydraulic impact force maximises the force with which the fluid hits the bottom of the hole. In both of these methods, there is only one circulation rate at which the hydraulics are optimised for a given maximum pump discharge pressure. For the case of maximum HHP this generally occurs when 65% of the total system pressure loss is at the bit nozzles. For maximum HIF the value is approximately 49% of total system pressure. In practice there is little to choose between the two procedures. If HHP is a maximum, the HIF will be within 90% of the maximum and vice versa. For this reason the proposed procedure details only optimisation based on Hydraulic Horsepower. 6.2

Field Method of Optimising Bit Hydraulics (HHP) For proper optimum hydraulics design, the pressure drops throughout the circulating system must be accurately determined. Rather than rely solely upon theoretical pressure loss calculations, it is preferable to measure the actual parasitic losses directly at the rig site. This is achieved by directly measuring the standpipe pressure and subtracting the calculated bit pressure loss. The advantage of this method is that since the bit pressure loss is independent of viscosity, it reduces errors due to the non-Newtonian nature of the drilling mud. The method also eliminates uncertainties due to out-ofgauge hole and temperature/pressure effects on viscosity. RIG SITE PROCEDURE 1.

Prior to POOH for a bit change, run the pumps at three or four different speeds and record the resulting standpipe pressures.

2.

From current nozzle size and mud weight determine pressure losses across the bit for each value of flowrate. From this value the parasitic loss (Pp) can be calculated by subtracting (PB) from standpipe pressure (PT).

3.

Plot the graph of parasitic pressure loss (Pp) against Q on log-log graph paper and determine the slope of this graph, which is the index U in the following equation: PB

4.

=

U PT U+1

From the above equation, PB can be calculated and hence the corresponding parasitic pressure loss (PP). PP

=

PT - PB

5.

The flowrate corresponding to this PP value can be read from the (PP) Vs (Q) plot.

6.

Finally the correct nozzle area can be calculated from: An

=

1/2

2

WQ (1303 P ) B

and nozzle size from: Nozzle Sizing (in 1/32nd)

=

32

1/2

( ) 4 An 3π

Note: Nozzle size should be rounded down to nearest value.

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EXA MPLE: The following information is recorded prior to tripping for a bit change: SPM GPM Standpipe Pressure, PT (psi)

140 692 3400 (max)

70 346 1000

35 173 350

Using standard oilfield hydraulics equations, the bit pressure loss for the given flowrates can be calculated, i.e. PB

=

W Q2 1303 AN2

where: W Nozzles -

1.37 SG 3 x 16/32”

Having calculated the bit pressure loss, we can compile the following table: SPM 140

70

35

GPM 692

346

173

Standpipe Pressure, PT

3400

1000

350

Bit Pressure Drop, PB

1451

363

91

Parasitic Loss, PP = PT - PB

1949

637

259

This table can be represented graphically. See Figure 9(a). From the graph we see that the slope “U” of the log (PP) vs. log (Q) line is 1.46. Therefore for maximum hydraulic horsepower: PB

=

U PT U+1

The desired surface pressure is 3400 psi. ∴

PB

=

( 1.461.46+ 1 )

PB

=

2018 psi

PP

=

PT - PB = 1382 psi

x 3400

This corresponds to a flowrate (QOPT) of 560 gpm. (Read off PP vs. Q line.) Therefore, the nozzle size required to give this pressure loss can be determined by re-arranging the bit pressure loss equation to give:

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An

=

(

An

=

1.37 x 560 (1303 x 2018 )

An

=

0.404 in2

W Q2 1303 PB

)

2

1/2

This area corresponds to 3 x 13/32” nozzles.

Note: The accuracy of this procedure is very dependent on gauge calibration and precise nozzle size measurement. 6.3

Recommended Nozzle Sizes The table below gives general guidelines on the normal range of nozzle sizes used for drilling various diameter holes. For top hole sections a high TFA should be used to provide maximum flow for hole cleaning (see Section 5). Hole Size

Nozzle Size (1/32 in)

(ins)

Min.

Opt.

Max.

26 17 1/2 12 1/4 8 1/2 6

3 x 18 3 x 18 3 x 12 3 x 11 3x8

-

3 x 28 3 x 24 3 x 20 3 x 16 3 x 11*

* Open if LCM required.

When smaller jet nozzles are installed, it is necessary to inspect the delivery strainer on the mud pumps to ensure that it is not damaged. Any holes in the strainer may result in blocked nozzles. Consider also using strainers in the drillpipe (cf. downhole motors).

Note: To prevent hydraulic washouts in soft formations, flowrate and nozzle combinations should be selected to maintain maximum jet velocities below 300 - 400 ft/s. 7.

PRESSURE LOSSES IN DOWNHOLE MOTORS AND MWD TOOLS

7.1

Downhole Motors As fluid is pumped through the mud motor with the tool running free off bottom, the pressure across the tool is constant provided the pump rate remains constant. This pressure represents the total system losses plus pressure drop across the bit and will vary with tool size and type. As the bit touches bottom and weight is added, the fluid circulating pressure increases. This increase in pressure is directly proportional to the additional bit weight or the drilling torque required. As more weight is added, the gauge pressure will increase until the maximum recommended pressure increase is reached. At this point the optimum torque is produced and the addition of more weight will increase gauge pressure until a point is reached where maximum design pressure is exceeded and stall may occur.

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The output rotational speed depends directly on flowrate, and the delivered torque is directly related to the pressure differential across the motor. To evaluate the pressure drop through a particular mud motor, the performance curve of the motor should be used. Table 7.1 gives an indication of the pressure drops occurring through tools when operating at optimum and maximum rates. Table 7.1 - Pressure Losses Through Mud Motors

Bit Differential Pressure Range

Motor Size (inches)

Length (ft)

Min.

Opt.

Drilex

3 1/2 4 3/4 6 3/4 8 1/4 9 1/2

12.5 21.0 24.0 23.5 24.0

-

Dyna-Drill (Delta 500)

5 6 1/2 7 3/4

19.8 19.9 21.0

(Standard)

9 5/8

(Delta 500)

Motor Pressure Drop (psi)

Max.

Flowrate Range (GPM)

Min.

Opt.

Max.

-

500 1500 1500 1500 1500

80-110 100-250 200-650 200-650 500-850

-

-

625-850 800-1000 800-1000 800-1000 800-1200

150 150 150

-

500 500 500

180-250 250-350 325-450

-

360 360 360

-

26.5

-

200

-

500-800

-

360

-

12

33.2

150

-

500

800-1200

-

360

-

(Delta 500) Plus 4

6 1/2 7 3/4

23.73 25.21

150 150

-

500 500

250-350 325-450

-

500 500

-

Delta 1000

3 7/8 5 6 1/2 7 3/4

22.5 21.5 24.75 27.0

200 200 200 200

-

1000 1000 1000 1000

100-150 180-250 250-350 325-450

-

625 375 500 500

-

Delta 1000 Slo-Speed

6 1/2 7 3/4

19.21 25.21

200 200

-

1000 1000

250-350 350-600

-

300 390

-

Christensen Mach 1

3 3/4 4 3/4 6 3/4 8 9 1/2 11 1/4

16.1 17.4 20.0 23.0 24.6 26.6

-

-

-

75-145 80-185 185-370 315-610 395-635 525-1055

-

-

640 580 580 465 640 520

Christensen Mach 2

1 3/4 2 3/8 3 3/4 4 3/4 6 3/4 8 9 1/2 11 1/4

8.9 13.1 19.4 20.0 26.6 26.9 32.8 32.2

-

-

-

20-45 29-73 75-185 100-240 200-475 245-635 395-740 525-1055

-

-

465 695 580 580 580 465 695 465

Christensen Mach 3

3 3/4 4 3/4 6 3/4 8 9 1/2 11 1/4

16.7 17.4 21.7 23.6 24.6 26.6

-

-

-

60-145 80-185 160-395 200-475 240-610 290-685

-

-

580 580 465 465 465 465

Company

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DRILLING HYDRAULICS

MWD Tools Table 7.2 indicates the pressure drops that can be expected through various MWD tools.

Table 7.2 - Pressure Losses Through MWD Tools

Company Teleco

Eastman Christensen

Gearhart

Anadrill

Exlog

Dynadrill

Tool Size (inches)

Length (ft)

Flowrates (gpm)

Pressure Drop Fluid Type

(psi)

9 1/2

30

320-1100

Water

100

450

8 1/4

30

320-1100

Water

100

450

7 3/4

30

320-1100

Water

100

450

6 3/4

30

250-500

Water

60

250

9 1/2

18

N/A

10 ppg mud

9

18

N/A

10 ppg mud

8

18

N/A

10 ppg mud

6 3/4

18

N/A

10 ppg mud

150 80 150 80 150 80 150 80

1100 750 1100 750 1100 750 1100 750

9 1/2

33

250-1100

10 ppg mud

120

700

8

33

250-1100

10 ppg mud

120

700

6 3/4

33

250-1100

10 ppg mud

120

700

9

40

330-1200

Water

80

550

8

40

210-750

Water

90

350

7

40

210-600

Water

90

350

9 1/2

36

250-1500

10 ppg mud

115

700

8

36

250-1500

10 ppg mud

115

700

6 1/4

36

200-800

10 ppg mud

45

300

9 1/2

20

250-1200

Water

48

750

8 1/4

20

250-1200

Water

48

750

6 1/2

18

200-600

Water

127

750

@

(gpm)

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DRILLING HYDRAULICS

HYDRAULICS NOMENCLATURE PSURF

=

Pressure Loss in Surface Equipment

(psi)

PDS

=

Pressure Loss in Drill String

(psi)

PB

=

Pressure Loss Across the Bit

(psi)

PA

=

Pressure Loss in Annulus

(psi)

PT

=

Total System Pressure Drop

(psi)

PP

=

Parasitic Loss (= PT - PB)

(psi)

Pd

=

Pressure Drop

(psi)

W

=

Mud Weight

(SG)

PV

=

Plastic Viscosity

(cP)

YP

=

Yield Point

(lb/100 ft2)

Q

=

Flowrate

(gpm)

V – V

=

Velocity

(ft/min)

=

Average Velocity

(ft/min)

Vc

=

Critical Velocity

(ft/min)

Vn

=

Nozzle Velocity

(ft/sec)

Vs

=

Cuttings Slip Velocity

(ft/min)

L

=

Length of Pipe

(m)

Re

=

Reynolds Number

(Dimensionless)

dh

=

Hole Diameter (or Casing ID)

(inches)

dp

=

Pipe Diameter

(inches)

An

=

Total Nozzle Area

(inches2)

K

=

Consistency Index

(lb sn/100 ft2)

n

=

Flow Behaviour Index

(Dimensionless)

θ

600

=

600 Reading on V-G Meter

(lb/100 ft2)

θ

300

=


(lb/100 ft2)

θ

3

=


(lb/100 ft2)

θ

6

=


(lb/100 ft2)

Dp

=

Diameter of Cuttings

(inches)

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DRILLING HYDRAULICS FIGURE 1 HYDRAULIC PLANNING DECISION TREE

IS PENETRATION RATE LIMITED BY FORMATION HARDNESS OR ABILITY TO CLEAN THE HOLE?

FORMATION HARDNESS

HOLE CLEANING

HYDRAULIC OPTIMISATION

IS THE HOLE VERTICAL OR DEVIATED?

SELECT BIT NOZZLES BASED ON FIELD HYDRAULICS TECHNIQUE ( SEE SECTION 6 )

VERTICAL

DEVIATED

DETERMINE MINIMUM FLOWRATE AT EXPECTED ROP. ( SEE SECTION 5 )

DETERMINE MINIMUM FLOWRATE AT EXPECTED ROP FOR THE HIGHEST HOLE ANGLE. ( SEE SECTION 5 )

SELECT SURFACE & DOWNHOLE EQUIPMENT TO MATCH FLOWRATE. ( SEE SECTIONS 4 & 7 )

SELECT SURFACE & DOWNHOLE EQUIPMENT TO MATCH FLOWRATE. ( SEE SECTIONS 4 & 7 )

DETERMINE PARASITIC PRESSURE LOSSES AT END OF BIT RUN FOR GIVEN FLOWRATE. ( SEE SECTION 4 )

DETERMINE PARASITIC PRESSURE LOSSES AT END OF BIT RUN FOR GIVEN FLOWRATE. ( SEE SECTION 4 )

DETERMINE Pbit ( SEE SECTION 4 )

DETERMINE Pbit ( SEE SECTION 4 )

IS Pbit POSITIVE?

IS Pbit POSITIVE?

YES

NO

NO

YES

SELECT BIT NOZZLES ( SEE SECTION 6 )

PRACTICE CONTROLLED DRILLING OR CHANGE MUD PROPERTIES

PRACTICE CONTROLLED DRILLING OR CHANGE MUD PROPERTIES

SELECT BIT NOZZLES ( SEE SECTION 6 )

IS NOZZLE VELOCITY LIKELY TO CAUSE HOLE WASH-OUT? ( SEE SECTION 6 )

IS NOZZLE VELOCITY LIKELY TO CAUSE HOLE WASH-OUT? ( SEE SECTION 6 )

YES

NO

NO

YES

2179 /166

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DRILLING HYDRAULICS FIGURE 2 EXAMPLE RHEOGRAM KCL/POLYMER MUD: 25 DEG C

80

60 RPM

DIAL READING

SHEAR RATE (S -1 )

SHEAR STRESS (lb/100ft 2)

3

3

5

3

6

4

10

4

100

20

171

20

200

31

342

31

300

39

511

39

600

58

1022

58

50 40 30 20 10 0 0

200

400 600 800 SHEAR RATE (s -1)

1000

1200

FIGURE 3 FLUID RHEOLOGICAL MODELS 100 BINGHAM PLASTIC

90 80

2

SHEAR STRESS (lb/100ft )

2

SHEAR STRESS (lb/100ft )

70

70

GENERALISED BINGHAM NEWTONIAN

60 50

POWER LAW

40 30 20 10 0 0

200

400 600 800 SHEAR RATE (s -1)

1000

1200

2179 /167

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DRILLING HYDRAULICS FIGURE 4

HOLE CLEANING MECHANISMS

ZONE 1

ZONE 2

GOOD HOLE CLEANING WITH MOVING CUTTINGS BED EFFICIENT HOLE CLEANING ZONE 4

SOME HOLE CLEANING, CUTTINGS BED FORMED

INCREASING ANNULAR VELOCITY

ZONE 3 SLOW REMOVAL OF CUTTINGS

ZONE 5 NO HOLE CLEANING

0

30

60

90

WELL INCLINATION (DEGREES)

2179 /168

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DRILLING HYDRAULICS FIGURE 5(A)

PROJECTION LINE

50

40

PROJECTION LINE

EFFECTIVE VISCOSITY EXAMPLE 1

CUTTINGS SIZE (in) 1 /4 30

EFFECTIVE VISCOSITY (cP) POINT A

300

1

17 / 2

1

/2

20

140 cP

POINT B 200

121/ 4

100

81/ 2

80

HOLE DIAMETER (in)

60

10

100 40 20

0

0

0



FIGURE 5(B)

PROJECTION LINE

CUTTINGS SETTLING VELOCITY EXAMPLE 1 PROJECTION LINE

SUBJECT:

Section


2.1

2.2 MUD SG 1.0 2.3

60

300 POINT C

2.4

50 1.5

200

45 ft/min 1.0 MUD SG

40 2.5

POINT D 30

1.5

100 2.6 20 1

/2 " CUTTINGS


2.0

2.7

CUTTINGS SG

2179 /169

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DRILLING HYDRAULICS FIGURE 5(C)

PROJECTION LINE

50

40

PROJECTION LINE


CUTTINGS SIZE (in) 1 /4


30

300 1

17 / 2

1

/2

20

200

121/ 4

100

1

8 /2

80

HOLE DIAMETER (in)

60

10

100 40 20

0

0


0 PLASTIC VISCOSITY (cP)

FIGURE 5(D)

PROJECTION LINE

CUTTINGS SETTLING VELOCITY DETERMINATION PROJECTION LINE

SUBJECT:

Section


60 50 40

2.1

2.2 MUD SG 1.0 2.3

30 60

300

2.0

20

2.4

50

1.5

200

40 1.0 MUD SG

2.5 10 1 /4 " CUTTINGS

30

1.5

100 2.6 20 1

/2 " CUTTINGS


2.0

2.7

CUTTINGS SG

2179 /170

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VERTICAL HOLE CLEANING EXAMPLE 1 CUTTINGS SLIP VELOCITY (ft/min) 50 40

60

30 20


10

30

0

PIVOT POINT

140 100 80

60

50

40

30

20

ANNULAR VELOCITY (ft/min) FIGURE 6(B) 17 1/2" VERTICAL HOLE CLEANING CHART CUTTINGS SLIP VELOCITY (ft/min) 60 50 40 30 20


10

50

0

40

30

20

PIVOT POINT

10

140 100 80

60

50

40

30


20 2179 /171

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DRILLING HYDRAULICS 12 1/4" VERTICAL HOLE CLEANING CHART

FIGURE 6(C)

CUTTINGS SLIP VELOCITY (ft/min) 50 60 40 30 20 PENETRATION RATE (m/h)

10 0

60 50

40

30

20

PIVOT POINT

10

40 30 180140100 80 60 50 ANNULAR VELOCITY (ft/min)

8 1/2" VERTICAL HOLE CLEANING CHART

20

FIGURE 6(D)

CUTTINGS SLIP VELOCITY (ft/min) 50 60 40 30 20 PENETRATION RATE (m/h)

10 0

40

30

20

PIVOT POINT

10

180 140100 80 60 50 40 30 ANNULAR VELOCITY (ft/min)

20 2179 /172

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DEVIATED HOLE CLEANING EXAMPLE 3 Q(gpm) * ESG TRANSPORT INDEX = ——————— 100

ESG = 1.32

40

1.2

2.3

1.3

1.4

1.5

950 * 1.32 TI = ——————— 100 = 12.5

30

20 TRANSPORT INDEX STEP 3

10

CUTTINGS SG

MAXIMUM ROP (m/h)

STEP 2

STEP 1 1.6

2.2

13 1.7

12 10 9 2.1 1.2

0 30


60

17 1/2" DEVIATED HOLE CLEANING CHART Q(gpm) * ESG TRANSPORT INDEX = ——————— 100 TRANSPORT INDEX

40

2.3

1.3 1.4 MUD SG

1.5

FIGURE 7(B)


17 30 16 15

20

14

CUTTINGS SG

MAXIMUM ROP (m/h)

1.5

2.2

1.6

13

10

1.7

12 11 10 9

0 30


60

2.1 1.2

1.3 1.4 MUD SG

1.5 2179 /173

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DRILLING HYDRAULICS FIGURE 7(C) 12 / " HOLE CLEANING CHART 14

Q(gpm) * ESG TRANSPORT INDEX = ——————— 100 TRANSPORT INDEX 11

50

2.5


1.6

30

10

20

9

CUTTINGS SG

MAXIMUM ROP (m/h)

40

2.4 1.7

8

10

7 2.3 1.2

0 40


80

1.3

1.4 1.5 MUD SG

1.6

FIGURE 7(D) 8 1/ 2" HOLE CLEANING CHART Q(gpm) * ESG TRANSPORT INDEX = ——————— 100 TRANSPORT INDEX

30

2.7

6

20 5

CUTTINGS SG

MAXIMUM ROP (m/h)

40


2.2 2.6

10 4 3

0 30

40


80

90

2.5 1.2

1.4 1.6 1.8 MUD SG

2.0

2179 /174

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DRILLING HYDRAULICS FIGURE 9 CIRCULATION PRIOR TO TRIPPING EXAMPLE

850m x 1.5 ( 0 deg )

NO. OF CIRCULATIONS EFFECTIVE LENGTH = ——————————— ACTUAL LENGTH

18 5/8" csg

=

5185 m ———— 2350 m

=

2.2 * B/U

300m x 1.7 ( 10 - 30 deg )

400m x 2.5 ( 30 - 60 deg )

800m x 3.0 ( 60 deg )

2179 /175

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DRILLING HYDRAULICS BIT HYDRAULIC OPTIMISATION EXAMPLE

FIGURE 9(A)

PRESSURE (PSI) 5000 4000 P max = 3400 PSI 3000 OPTIMUM BIT LOSS Pb 2018 PSI

PARASITIC PRESSURE LOSS

2000

1382 1000 900 800 700 600 500 400

300 SLOPE = 1.46 200 100

200

300

400 500 600700

CIRCULATION RATE (gpm)

RIG DATE MUD TYPE DEPTH PUMP RATE (SPM) PUMP RATE (GPM) STANDPIPE PRESSURE, P T BIT PRESSURE DROP, PB PARASITIC LOSS, PP =PT -PB

900 800 1000 Q OPT = 560 gpm

WELL NO. HOLE SIZE MUD WEIGHT: 1.37 SG T.F.A: 3 x 16/32 ins 2 140 70 692 346 3400 1000 1451 363 1949 637

35 173 350 91 259 2179 /176

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DRILLING HYDRAULICS FIGURE 9(B) BIT HYDRAULIC OPTIMISATION WORKSHEET 5000 4000

3000

2000

PRESSURE PSI

SUBJECT:

Section

1000 900 800 700 600 500 400

300

200 100

200 300 400 CIRC RATE G.P.M.

RIG DATE MUD TYPE DEPTH

500 600 700

900 800 1000

WELL NO. HOLE SIZE MUD WEIGHT T.F.A. ins 2

PUMP RATE (SPM) PUMP RATE (GPM) STANDPIPE PRESSURE, PT BIT PRESSURE DROP, PB PARASITIC LOSS, PP =P T -PB 2179 /177



Index Prefixes 0000


1000

Drilling

2000

Casing and Tubing

3000

Cementing

4000

Drilling Fluids

5000


6000


7000

Well Evaluation

8000






Section

Description

5000

WELLHEADS, PACKERS, TOOLS & EQUIPMENT

5010/SEM

Subsea Guideline Wellhead Systems - General

5030/JAK

Mudline Suspension Systems

5035/JAK

Prep. & Run PLEXUS “CENTRIC 15”, Mudline Suspension System

5200/GEN

Packers: Baker (Brown) JM Compression Set Tie-Back Packer

5205/GEN

Packers: Baker (Brown) CPH Hydraulic Set Tie-Back Packer

5210/GEN

Packers: TIW SN-6 Retrievable Tie-Back Packer

5215/GEN

Packers: Bridge Plug Setting General

5220/GEN

Packers: EZ-Drill-SV Squeeze Packer

5225/GEN

Packers: Bobcat Retrievable Bridge Plug

5227/GEN

Packers: Arrow DLT Packer, Unloader and Storm Valve

5230/GEN

Packers: Johnson Hurricane Packer

5235/GEN

Packers: Halliburton RTTS Packer

5237/GEN

Packers: BJ Services Mode 1223 Packer

5400/GEN

Drilling Jars

5410/GEN

Hydril Retrievable Drop-In Check Valves

5420/GEN

Drill Stem Ciruculating Subs

5440/GEN

Bypass Valves

5460/GEN

Drill String Lifting and Handling Equipment

5500/SEM

Heave Compensation Systems


SUBJECT:


5050/FOR

Wellhead System Forties FA/FC

5050/CLY

Wellhead System Clyde

5050/MAG

Wellhead System Magnus

5050/BRU

Wellhead System Bruce

5050/AME

Wellhead System Amethyst

5050/WYF

Wellhead System Wytch Farm

5051/FOR

Wellhead System Forties FB/FD


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SUBSEA GUIDELINE WELLHEAD SYSTEMS - GENERAL

GENERAL The standard subsea wellhead system used by XEU for exploration and appraisal drilling is the Universal Wellhead system. The following text clarifies the use of the individual components used in the Universal Wellhead system. Technical details of the components can be found in the latest revision of the Universal Wellhead Specification DTG/D/29/89. All components will be supplied by the manufacturer according to the Specification.

2.

COMPONENTS The components will be run as described below. Drawings and vocab numbers are not included because of the differences in detail between individual manufacturers’ systems. Equipment details can be found in the respective operating manuals, which are specific to each rig.

2.1

TGB The TGB will only be used if an operational area has a particularly high seabed slope, weak soil and/or if water depth conditions dictate. A TGB will only be supplied to the rig if such conditions exist. To accommodate a large seabed slope, the TGB has a receiver for the PGB gimbal to permit angular misalignment between the TGB and PGB.

2.2

PGB The PGB shall be run on all wells. The PGB has a detachable gimbal to land in the TGB gimbal receiver. If the TGB is not required then the PGB gimbal should not be ordered with the PGB. The standard PGB latch mechanism for the 30” housing allows the housing to be stabbed in place without aligning lockdown bolts. The underside of the PGB has locating bars to stop the PGB from skidding on the spider beams when making up the 30” housing. The PGB carries locating points for bullseyes and acoustic beacons. The PGB has standard guide posts fitted with Regan style post tops for reconnecting guidelines in the event of breakage; the posts are numbered to be consistent with present subsea numbering practise and are replaceable with ROV/diver assistance. The guide posts have guideline attachment points directly underneath the posts so that guidelines can be run when the TGB is not run. Cement top-up is provided for by stinger guide funnels fitted in the four quadrants of the PGB.

2.3

30” Housing The 30” housing and conductor string shall be run on all wells. The 30” is run on a cam actuated running tool which is latched into the top of the 30” housing. The 30” housing is then latched into the PGB. The extension joint is a welded extension to the 30” housing and is a standard component consisting of a Vetco RL-4 connector box down with heavy wall (1.5”, 456.57 lbs/ft, X52) 9m long joint. A second heavy wall joint is normally run to accommodate the load transfer from the rigid lockdown in the well body and to allow for cement shortfalls. The length, weight and grade of the 30” conductor and connectors below the extension joint will be specified in the drilling programme.

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The 30” can accept a standard internal latch (pin connector) to allow mud returns when drilling the 26” hole section. The profile of the internal latch will be specific to individual manufacturers. 2.4

Wellhead Body The 18 3/4” 15,000 psi Universal Wellhead body shall be run on all wells, whether they are single or dual BOP stack systems. The wellhead has a connector profile compatible with a Cameron Ironworks model 70, 10,000 psi connector or a model HC, 15,000 psi connector. No other connector profile can be used. The wellhead body has a rigid lockdown mechanism which is used and activated on each well. The rigid lockdown is used to transfer operational loads from the wellhead into the 30” conductor away from the surface casing. The wellhead body extension joint shall be run as detailed in the Specification (20” x 0.812”, 166.4 lbs/ft X56, 2m long using a Vetco RL-4S pin down connection). However, the surface casing and connectors are unspecified to allow flexibility for the individual well and will be indicated in the drilling programme. This flexibility allows 20” or 13 3/8” surface casing to be run. The 20” can be run connected to the wellhead extension joint by the RL-4S connector. The 13 3/8” can be run by connecting a 20” x 0.625” pup joint plus crossover joint with a 13 3/8” buttress casing thread to the extension joint. This crossover is a standard BP component. The Universal Wellhead body has provision for running dual or single stack (13 5/8” or 18 3/4”) components. This maintains exploration and completion flexibility and compatibility with BP’s single and dual BOP stack drilling rigs. The design of the wellhead body ensures that it will be compatible with existing completion options used by BP.

2.5

Casing Hangers The following casing hangers can be suspended within the Universal Wellhead body: 13 3/8”, 9 5/8” and 7”. An option exists to run 16” as a liner below the wellhead and a 10 3/4” hanger in the wellhead in place of the 9 5/8” hanger. All casing hangers have standard extension joints and, like the 30” housing and wellhead body, allow flexibility for choosing the relevant casing. The casing hangers are run on tools which run and set the pack-off at the same time, i.e. single trip. Each hanger can also be run on full bore running tools but in this case the pack-off has to be run separately.

2.6

Pack-Offs All pack-offs shall be run as a matter of course to seal the respective hanger and wellhead annulus. The pack-offs are recoverable and do not restrict retrieval of the casing hanger system. All pack-offs, except the emergency pack-off, have metal-to-metal seals. Each casing hanger pack-off is interchangeable (except dual to single stack systems) so that stock levels can be rationalised. All pack-offs are weight set and require straight pull to retrieve.

Note: When pulling annulus pack-offs (particularly during abandonment operations), there is a strong likelihood of an accumulation of gas underneath the pack-off. Caution should be observed to ensure the gas is contained by closing BOPs and diverter at appropriate times immediately prior to pulling the pack-offs. Consideration should be given to punching the casing below the pack-off and venting the gas under controlled conditions prior to pulling the pack-off.

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Wear Bushings and Bore Protectors For all operations wear bushings and bore protectors are run to protect the casing hangers and bore of the wellhead. The design of the components means that BOP stack testing can be carried out with the wear bushing in place. They are also held positively in place once run. Isolation (of the uppermost pack-off) pressure testing and non-isolation pressure testing can be achieved with the wear bushings run or retrieved. The bore protector has to be removed to do any pressure testing.

2.8

Running and Test Tools The number of running tools has been kept to a minimum so that any one tool will carry out many functions. All tools have a positive method of indicating that they have been activated correctly. In the case of pack-off running tools, the pack-off will always be recovered on the running tool if it does not set, even if a positive pressure test is achieved. Right hand rotation is standard and the use of “J” activated tools is minimised. Full bore casing hanger running tools are available to maintain flexibility in cementing and designing casing.

2.9

Dual BOP Stack System Conversion Components The use of dual BOP stack rigs is currently limited to BP’s two rigs - the Sea Explorer and the Sedco/BP 711. If contracted, other dual BOP stack rigs would have to be fitted with crossover wellhead connectors. In all cases the Universal Wellhead conversion components would be run. The UWHD system allows crossover to the dual BOP stack system from a single BOP stack system wellhead. The single BOP stack wellhead size is 18 3/4” nominal ID and the dual BOP stack sizes are 21 1/4” and 13 5/8” nominal ID respectively. The standardised nominal size of the wellhead body is 18 3/4” which is applicable to dual and single BOP stack bodies. The 21 1/4” BOP stack uses a wellhead connector, with an internal crossover from 21 1/4” nominal ID to 18 3/4” nominal ID. Likewise, the 13 5/8” BOP stack uses a wellhead connector with an internal crossover from 13 5/8” nominal ID to 18 3/4” nominal ID. When using a dual stack rig the 18 3/4” wellhead bore is reduced to 13 5/8” for running the 9 5/8” and the 7” components. Tubing hanger adapters for SWOPS, the CTH or conventional dual bore completions are also available.

2.10

Debris Cap The debris cap is provided to allow suspension of the well for future possible development. The debris cap is simple to use and one design and size can be run on either single or dual BOP stack systems. The cap is run and landed on the outside of the wellhead body by a straight stab and retrieved by overpull. If it is not set correctly, then it will be retrieved on the running tool. Anti-corrosion fluid can be injected through the drill pipe running string into the debris cap to protect the casing hangers and seal areas during suspension.

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Tie-Back Facility Tie-back facilities are not required for exploration or appraisal drilling but by specifying the UWHD the wellhead will be suitable for subsequent tie-back if the well is to be developed.

2.12

Completion Requirements Completion requirements are not required for exploration or appraisal drilling. However, by specifying the UWHD the wellhead will be suitable for all subsequent completions involving SWOPS and CTH (or other methods, by design). Once the well has been drilled, tubing hanger adapter sleeves require to be run into the wellhead to permit completion by the chosen method, e.g. SWOPS or the CTH.

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MUDLINE SUSPENSION SYSTEMS

1.

GENERAL

1.1

On wells where future tieback is possible, the following points should be taken into consideration: 1.

The landing ring on the conductor should be positioned relative to seabed so that the stacked suspension system can be inspected prior to tieing back.

2.

Procedures for the suspension of a well should be followed closely and accurately recorded. Temporary abandonment caps should be run and their correct installation confirmed.

3.

A mechanical release should be run on the conductor so that the hanger assembly is not damaged during recovery or by swarf from cutting operations during suspension.

4.

A secure debris cap should be fitted after suspension.

5.

The mudline suspension hangers should be positively centralised.

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PREPARATION AND RUNNING OF INGRAM-CACTUS "CENTRIC 15" MUDLINE SUSPENSION SYSTEM

Note: The Ingram-Cactus system described here was previously known as the PLEXUS system. Change of name merely reflects change of company ownership. 1.

30” CONDUCTOR STAGE

1.1

Preparation Prior to running 30” conductor, check the following:

1.2

1.

The 30” conductors connectors should have anti-rotation locking devices to allow turn to release at the seabed connector.

2.

Check position of the landing ring (if fitted); minimum ID is 26 1/4” and ensure a 26” bit and 20” spring bow centralisers will pass through.

3.

Check that the ID of connectors above the mudline is compatible with the OD of the mudline equipment and any centralisers required.

Running 1.

Run 30” conductor as required. The 30” should be spaced out such that the seabed connector is approximately 1.5m above the mudline and the landing ring is 6 to 12m below mudline.

Note: Alternatively, as it is not essential to land-off the 20” mudline hanger, the conductor can be driven to refusal. 2.

Run the cement stinger, complete with centraliser, with the 30” supported in the spider and slips, handling the drillpipe with two elevators and plate.

3.

Stab in and circulate, check for returns at the seabed.

4.

Cement as required, check for backflow. Pull out of hole with stinger and wait on cement.

2.

20” CASING STAGE

2.1

Preparation The 20” hanger running tool is shipped as an assembled joint usually box up by pin down. Before running in the hole, check the following: 1.

Confirm the OD of the mudline equipment and any centralisers are compatible with the 30” connectors down to the mudline.

2.

Check torque between the running tool and hanger by turning running tool one turn to the right, then re-make one turn to the left, ensuring torque is a maximum of 2,500 ft.lbs over running torque.

3.

If any problems are encountered during this check, the running tool should be released for inspection.

4.

To release the running tool, turn 7 turns to the right, the tool will rise by 2 1/4”.

5.

Remove the tool and inspect threads and the 3 “O” ring seals.

6.

Check the hanger faces and threads for damage or debris.

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2.3

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7.

Re-grease hanger and running tool with an API approved general purpose grease.

8.

Make up the hanger and running tool, turning 7 turns to the left and applying a torque of 1,000 ft.lbs optimum, 2,500 ft.lbs maximum over running torque.

Running 1.

Run the 20” casing as per Casing Section 2200/FIX, ensuring the rotary table is locked while each casing connection is made up. This will avoid backing off the mudline running tool (left hand thread).

2.

Run cement stinger as per Cementing Section 3200/FIX or 3210/FIX. Rig up to cement casing.

20” Washout Operation 1.

After cementing, pull back three to four stands of the cementing string. Stinger should be at least 1 stand above float equipment during washout procedures.

2. a)

Install the 20” manipulation tool. Run in until the tool tags the 13 3/8” landing profile in the 20” hanger. Pick up until the locating ring on the tool engages in the wash sleeve profile (approximately 1.5m).

b)

If the torque tool spaceout sub is used below the 20” manipulation tool, location of the tool will be achieved when the spaceout sub lands on the 13 3/8” landing profile in the 20” hanger.

Note: Correct location of the tool is indicated by high torque when stinger is turned to the left. 3.

Make up the 20” stuffing box circulating head.

4.

Balance the cement string weight and open the washsleeve by turning the drillpipe 7 turns to the right, to expose the washports.

Note: If torque build-up is high, take care not to break connections. 5.

Pump through the circulating head, maintaining high pump rates to achieve sufficient annular velocity for washout.

6.

If required, pump through the drillpipe at the same time using the cement lines.

7.

Spot 10 bbls of inhibitor or sugar water across the washports to inhibit cement migration.

8.

Close the washsleeve by balancing the cement string weight and turning 7 turns to the left until a torque build-up is noticed.

9.

Carry out a low pressure test to ensure washports are sealed then remove the circulating head and pull out of hole with cement string and torque tool (20,000 lbs overpull may be required to release the tool from the profile).

BP EXPLORATION


13 3/8” AND 9 5/8” CASING STAGE

3.1

Preparation

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3.

3.2

Section

1.

Check that OD of hangers are compatible with the ID of the previous casing down to the mudline.

2.

Check the torque between the hanger and running tool by rotating the running tool one turn to the right, then make up one turn to the left, ensuring maximum torque used is 2,500 ft.lbs over running torque.

3.

If any problems are encountered during this check, release the running tool by turning 14 turns to the right.

4.

Remove the running tool and inspect threads and seal faces for damage or debris, also inspect the mudline hanger. Check the 3 “O” ring seals.

5.

Re-grease hanger and running tool with API approved general purpose grease. Make up the hanger and running tool by turning 14 turns to the left and torque to 1,000 ft.lbs optimum, 2,500 ft.lbs maximum over running torque.

6.

If washout is not required, make up the running tool to 5,000 ft.lbs to utilise the metal seal capability.

Running 1.

Run the casing as per Casing Section 2300/FIX or 2400/FIX, ensuring the rotary table is locked while each connection is being made up to avoid backing off the mudline running tool (left hand thread). Make casing connections up to maximum recommended torque.

2.

Cement as per Section 3300/GEN or 3350/GEN.

Washout Operation 1,

On completion of cementing, unlock the blocks and balance landing string weight.

2.

Mark casing at rotary table with vertical and horizontal mark.

3.

a) Turn 13 3/8” casing 6 turns to the right, casing will rise 2”. b) Turn 9 5/8” casing 8 turns to the right, casing will rise 2 1/2”.

Note: Keep string weight balanced. 4.

Circulate through cement head or circulating head until clear returns are seen, maintaining high pump rates.

5.

Spot 10 bbls of inhibitor or sugar water at the mudline.

6. a)

Close washports by turning 13 3/8” casing 6 turns to the left, casing will descend 2” and torque will build.

b)

Close washports by turning 9 5/8” casing 8 turns to the left, casing will descend 2 1/2” and torque will build.

Note: Final torque should be 2,500 ft.lbs over running torque. 7.

Pressure test string to check for leaks, observe annulus for returns.

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INGRAM-CACTUS “CENTRIC 15” MUDLINE SYSTEM TYPICAL TIE-BACK PROCEDURE 1.

Prior to running the tie-back string, run in with a jetting sub to clean the tie-back threads and seal areas.

2.

The 20” tie-back tool has a pre-aligned right hand thread and requires 2 1/2” turns for make-up, with landing string weight down.

3.

All the tie-back tools have 2 resilient seal positions in case a mudline hanger seal area has been previously damaged.

4.

The 13 3/8” and 9 5/8” tie-back tools are stab-in type tools, installed as follows: a)

Run landing string and seal weight down to stab in the tie-back tool.

b)

Turn up one turn to the left with 5,000 ft.lbs of torque to set the double nose metal seals.

c)

Test the tie-back with either a tie-back test tool or pressure against the casing and monitor annulus.

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BP EXPLORATION

DRILLING MANUAL

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SUBJECT: PACKERS: BAKER (BROWN) JM COMPRESSION SET TIE-BACK PACKER 1.1

A Baker (Brown) compression set tie-back packer will be run in the event that the 7” or 5”/4 1/2” liner lap is leaking.

1.2

The standard JM tie-back packer has 3 sets of chevron seals which seal inside the top 1m of the liner PBR. Additional seals can be run below the packer if required when tying back to a 20 ft (7m) PBR.

Note: Check seal type is suitable for well conditions (temperature, pressure, etc.). 1.3

In the case of a 7” liner lap leak, make up the following assembly to dress the top edge of the liner PBR and to remove any cement from the seal bore of the PBR: 5 7/8” / 6” Bit Bit Sub 1 - 3 x 4 3/4” Drill Collars Fluted Tie-Back Mill Spacer Sub Top Dressing Mill 9 5/8” Rotating Casing Scraper Crossover if required 9 x 6 1/2” Drill Collars Crossover

-

3 1/2” Reg pin. 3 1/2” Reg box x 3 1/2” IF box. 3 1/2” IF pin x box, if available. 3 1/2” IF pin x 4 1/2” IF box. 4 1/2” IF pin x 4 1/2” Reg box. 4 1/2” Reg pin x pin. 4 1/2” Reg box x pin. 4 1/2” Reg pin x 4” IF box. 4” IF pin x 4” IF box. 4” IF pin x 4 1/2” IF box.

Notes: a)

The top dressing mill should have thread locking cement put onto all of its cutting faces before being run. After milling, the thread lock cement should only be worn or missing from the lower cutting faces, indicating that the mill has dressed the top of the liner PBR.

b)

Space the mills to suit the length of the PBR in place on the liner hanger (refer to the drawing on page 4).

RIH and tag the liner top with the top dressing mill. Pull back 3m and rotate the assembly above the liner at 30 rpm. Dress the top of the PBR with a set down weight of 5 - 10,000 lbs with 30 - 60 rpm for a maximum of 15 minutes. Pull back, pump a viscous slug and circulate bottoms up to remove any milled cuttings.

Note: When cleaning out and dressing the PBR, DO NOT: a) b)

Rotate in one place for longer than 5 minutes. Slack off more than 10,000 lbs on top of the PBR.

1.4

If required, log 7” CBL/VDL/GR/CCL. Note that if no 9 5/8” CBL has been logged previously then the tools should be centralised to allow both casings to be logged in one run. (This procedure is acceptable for a near vertical well only).

1.5

If required, run gauge ring/junk pusher to top of the PBR. Gauge ring to be midway between packer OD and casing drift diameter: OD Tie-Back Packer Drift ID 9 5/8” 47 lb/ft Casing Drift ID 9 5/8” 53.5 lb/ft Casing

1.6

8.25” 8.525” 8.378”

Pick up the tie-back packer assembly. Check all slips for cracks and all seals for cuts or other damage prior to running.

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SUBJECT: PACKERS: BAKER (BROWN) JM COMPRESSION SET TIE-BACK PACKER Note: Apply left-hand torque on the running tool to ensure that the tool is correctly made up before RIH (use a rig tong on the packer body and a wrench on the running tool). 1.7

RIH slowly with the tie-back packer to the top of the liner.

Notes: a)

The body of the packer has an 8 1/4” OD. The small annular clearance in the 9 5/8” casing will force mud over the top of the drillpipe for a few stands when running in. In 9 5/8” 53.5 lb/ft casing a heavy slug may be necessary to prevent this, or alternatively, the use of a bypass tool can be considered (refer to Section 5440/GEN).

b)

RIH slowly to avoid pressure surges.

c)

Do not rotate the string to the right.

1.8

Make up the kelly or top drive and chicsans. Space out so the kelly/single is at an acceptable working height above the rotary and that no tool joint is situated opposite the annular preventer or rams when compression set packer is stabbed into the PBR.

1.9

Check up and down weights with the pump off.

1.10

Circulate slowly for 5 minutes before carefully stabbing into the PBR with 200 psi circulating pressure. Stop the pump as soon as a pressure increase is observed and release pressure. Ensure DP remains open, or chicsan line is broken. Stab fully into the PBR (+/- 1m) until a positive weight loss is observed. Do not allow the packer to take more than 5000 lbs weight.

1.11

After entering the packer stem fully into the liner PBR, slack off 25,000 lbs onto the setting shoulder and apply 500 psi down the drillpipe with the annulus open to check for leaks. If no leak is apparent, set down an additional 20,000 lbs and increase the pressure to 1000 psi. If no leak is observed, slack off a further 20,000 lbs and increase pressure to 1500 psi and hold for 15 minutes.

Notes:

1.12

a)

The above procedure maintains a downward weight of +/- 7000 lbs at the packer and will not allow the packer to be pumped out of the PBR.

b)

If the pressure test is not successful, pick up, circulate and re-stab the packer as per 1.10. Repeat the entire test procedure. If no successful pressure test is obtained, do not set the packer but retrieve it and inspect the seals.

Bleeding off the above test pressure will automatically set the packer. Alternatively, reverse the above procedure, i.e. bleed off 500 psi and pick up 20,000 lbs, etc. until all the pressure and weight has been removed. The packer can then be set with 60,000 - 80,000 lbs (deviated wells); a ± 30,000 lbs weight decrease should be observed as the packer pins shear and the inner mandrel plus PBR seal stem move down a few inches. Maintain set down weight on the packer for 15 mins.

Note: The shear value of the pins is 55,000 lbs. 1.13

Pick up and pull 25,000 lbs overpull above recorded up weight. Set down weight on the packer and test annulus 1500 psi for 15 mins.

1.14

If an internal pressure test is required, pressure test through the drill pipe to 2500 psi for 15 mins to test the lower seals.

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SUBJECT: PACKERS: BAKER (BROWN) JM COMPRESSION SET TIE-BACK PACKER Note: Set down 15,000 lbs per 500 psi of drillpipe pressure required in order to compensate for the piston effect of the running tool and ballooning of the drillpipe. For example, for a 2500 psi internal test, set down 75,000 lbs on the packer. 1.15

Release pressure.

Note: If a further annular test is required, do not have more than 20,000 lbs set down weight on the packer before testing. 1.16

Pull back to neutral weight of the running string, less 15,000 lbs. Release running tool with 10 turns RH rotation.

1.17

POH.

1.18

Where gas formations are behind the liner or formation pressure behind overlap is greater than the reservoir pressure, an inflow test with a packer will be considered. (Refer to Section 3560/GEN.) Any variations to the above test pressures will be advised in the Drilling Programme.

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SUBJECT: PACKERS: BAKER (BROWN) JM COMPRESSION SET TIE-BACK PACKER

P.B.R. TOP DRESSING MILL ( REVERSIBLE ) & POLISH BORE MILL - 7" LINER

4 1/2 " REG 2 1/4 " I.D. 6 1/4 " O.D. 7 3/8 " O.D. 1/16" PARTICLE TUNGSTEN CARBIDE 71/2 " O.D. 81/2 " O.D. 60° 81/4 " O.D.

6"

5" 2"

11" P.B.R. TOP DRESSING MILL

71/2 " / 71/4 "I.D. DEPENDENT UPON PRESS. 4 1/2 " I.F. 61/8" O.D.

SPACER SUB 2 / " I.D. 14

SPACER SUB LENGTH DEPENDENT UPON P.B.R.

TIE-BACK MILL

41/2" I.F. 8" 18

6 / " O.D. 7 7/16" O.D. FOR STANDARD P.B.R. 2 11/16" I.D.

12"

1"

30° 4 3/4 " O.D.

6"

31/2 " I.F.

2179 / 1

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PACKERS: BAKER (BROWN) CPH HYDRAULIC SET TIE-BACK PACKER

1.1

A Baker (Brown) CPH hydraulic set tie-back packer will be run in the event that the 7” or 5”/4 1/2” liner lap is leaking.

1.2

In the case of a 7 “ liner lap leak, make 6” bit and tandem 9 5/8”/7” scraper run, spacing out so that the 9 5/8” scraper will clean up the tie-back packer setting area. Include on the same assembly the polish bore mill, spacer sub and PBR top dressing tool, as per drawing on page 3. Space the mills to suit the length of PBR in place on the liner hanger. The teeth of the PBR top dressing mill should be filled with Bakerlock before going in hole so that a wear pattern can be seen when the tool is pulled. Set down 2000 - 4000 lb at 50 RPM for four minutes only. Pick up and pump a viscous pill to clean up cuttings. ENSURE POLISH BORE MILL IS CORRECT OD TO FIT PBR IN PLACE. POH.

Note: When cleaning out and dressing the PBR, DO NOT: a) Rotate in one place for longer than 5 minutes. b) Slack off more than 10,000 lbs on top of the PBR. 1.3

Log 7” CBL/VDL/GR/CCL. Note that if no 9 5/8” CBL has been logged previously then the tools should be centralised to allow both casings to be logged in one run. (This procedure is acceptable for a near vertical well only).

1.4

If required, run gauge ring/junk pusher to top of the PBR. Gauge ring to be mid way between packer OD and casing drift diameter.

1.5

Check: a)

That the packer, seal stem and PBR dimensions and part numbers correspond with the appropriate drawing in this section.

b)

That the seal stem is the correct item to fit the PBR in place, i.e. length and seal OD.

c)

That the packer tie back PBR is correct length, OD, ID, and pressure rating for the application required and conforms with programme requirements.

d)

Size and number of shear pins for: 1. Setting packer elements. 2. Setting slips. 3. Setting tool shear out sub.

1.6

e)


f)


g)

Seating of ball in shear out sub.

h)

Pressure rating of shear disc and size of back up washer.

i)

Running tool pack off seals fit packer PBR.

j)

Free passage of setting ball through all tools in string.

Make up the running assembly. Ensure sufficient DC and HWDP are used to overcome the pump out pressure, i.e. 7” tools pump out force is approx 20,000 lbs per 500 psi. Check the setting ball has been removed from setting tool and RIH slowly with the tie-back packer (minimum 2 mins/stand).

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Make up the cementing landing single, complete with Brown plug launch head and pressure test lines to above shear out/test pressures. 1.7

Check up and down weights with the pump off.

1.8

Circulate for a short period, with the pump and carefully stab into the PBR. Stop the pump as soon as a pressure increase is observed and release pressure. Ensure DP remains open. Stab fully into the PBR and bottom out with 20,000 lbs. Weight down cannot set the CPH hydraulic set packer.

1.9

Pressure test down the drill pipe to 2000 psi for 15 mins. An additional 20,000 lbs weight must be set before each 500 psi internal pressure increment to avoid potential pump out of the packer stem seals.

1.10

With the DP open, make a 1500 psi, 15 min annulus test in 500 psi stages. If liner lap is leaking, do not exceed the leak off pressure at the 9 5/8” casing shoe.

1.11

Pressure up and rupture shear disc which is normally set for 2500 psi. Ensure sufficient weight is on the packer.

1.12

Drop 1 1/2” setting ball and circulate ball to seat at a minimum circulating rate.

1.13

Increase pressure slowly to 2500 psi to set the packer.

1.14

Pick up 20-40,000 lbs above upstroke weight to test hold down slips on the packer.

1.15

If packer is set, set weight on packer and pressure down drill pipe to 3000 psi to shear out the ball seat.

1.16

Pull back to neutral weight less 15,000 lbs and release running tool with 10 right hand turns.

1.17

Pressure test the complete liner overlap to 3500 psi for 15 mins against the pipe rams. Proceed carefully as in a leak off test in case there is a leak past the packer down the overlap.

1.18

POOH.

1.19

An inflow test with a packer may be considered. (Refer to Section 3560/GEN.)

Any variations to the above test pressures will be advised in the Drilling Programme.

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P.B.R. TOP DRESSING MILL ( REVERSIBLE ) & POLISH BORE MILL - 7" LINER 4 1/2 " REG 2 1/4 " I.D. 6 1/4 " O.D. 7 3/8 " O.D. 1/16" PARTICLE TUNGSTEN CARBIDE 71/2 " O.D. 81/2 " O.D. 60° 81/4 " O.D.

6"

5" 2"

11" P.B.R. TOP DRESSING MILL

71/2 / 7 1/4 I.D. DEPENDENT UPON PRESS. 4 1/2 " I.F. 61/8" O.D.

SPACER SUB 2 / " I.D. 14

SPACER SUB LENGTH DEPENDENT UPON P.B.R.

TIE-BACK MILL

41/2" I.F. 8" 18

6 / " O.D. 7 7/16" O.D. FOR STANDARD P.B.R. 2 11/16" I.D.

12"

1"

30° 4 3/4 " O.D.

6"

31/2 " I.F.

2179 / 10

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PACKERS: BAKER (BROWN) CPH HYDRAULIC SET TIE-BACK PACKER 7" CS SETTING TOOL WITH P.B.R. SEAL ASSEMBLY WITH 4 1/2 " I.F. HYDRAULIC PUSHER ASSEMBLY AND C.P.H. PACKER

CHEVRON SEALS O.D. 5" 4" I.D. 3 1/2 " LENGTH 3' 0"

CHEVRON SEALS 5" O.D. 4" I.D. 3 1/2 " LENGTH 1 1/2 " BALL DIAMETER

1' 0" 10' 4 3/4 "

PRESSURE RUPTURE DISC ASSEMBLY CONTROL WASHER I.D. BURST PRESSURE 1 /2 " 2700 - 2800 PSI 9 /16 " 2400 - 2500 PSI 5 /8 " 2100 - 2000 PSI RUPTURE DISC IS ALWAYS .010" THICK BRONZE

NORMAL P.B.R. LENGTH AS SHOWN VARIATIONS ARE AVAILABLE 11' 1 1/2 " AND WILL BE ADVISED IN PROGRAMME

4' 3 1/4 "

P.B.R SEAL ASSEMBLY PART No. 22124 SEAL 7 1/2 " O.D. 6 3/4 " I.D. GLASS FILLED TEFLON MOLYGLASS CHEVRON

LINER PACKER, BROWN TYPE C.P.H., PRT. No.120747 7" 29 lb/ft x 9 5/8 " 47-53.5 lb/ft 8RL BOX DOWN 8.250" O.D. 6.278" I.D. WITH POLISHED BORE RECEPTABLE EXTENSION 8.250" EXTENSION 7.500" O.D. HONED EXTENSION I.D. 4140 HT 110,000 PSI MINIMUM YIELD THROUGHOUT

1' 4"

6 1/2 " SHEAR PINS 3 x 7/16 " 13,200 lbs

THREAD 6.278" I.D. TWO THREADS PER INCH DOUBLE HELIX PACKER SEAL ELEMENT 8 1/4 " O.D. 2 BACK UP RINGS 11784 2 END SEALS 119720 1 MIDDLE SEAL 113945

THREAD 7" 8 RD. LONG

6 1/2 " SHEAR PINS 9 x 7/16 " 39.000 lbs 8.25"

8 3/4 "

7.000"

9"

7.656

9"

7.250"

1' 4"

7.500" 2' 7 3/4 " 7.000"

7 7/16 "

SEAL MANDREL PRT. No. 114406 6' LONG WITH 3 SETS OF MOLYGLASS SEALS PRT. No. 22127 O.D. 7.5" MANDREL BORE 6.187 414 HT 110,000 PSI MIN. YIELD

1 1/4 " 1' 0" 2179/12

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7" CS SETTING TOOL WITH P.B.R. SEAL ASSEMBLY WITH 4 1/2 " I.F. HYDRAULIC PUSHER ASSEMBLY AND C.P.H. PACKER HIGH PRESSURE EQUIPMENT

CHEVRON SEALS O.D. 5" 4" I.D. 3 1/2 " LENGTH

CHEVRON SEALS 5" O.D. 4" I.D. 3 1/2 " LENGTH 1 1/2 " BRONZE SETTING BALL O.D. PART No. 17398 PRESSURE RUPTURE DISC ASSEMBLY CONTROL WASHER I.D. BURST PRESSURE 1 /2 " 2700 - 2800 PSI 9 /16 " 2400 - 2500 PSI 5 /8 " 2100 - 2000 PSI RUPTURE DISC IS ALWAYS .010" THICK BRONZE 21' 6 1/2 " P.B.R SEAL ASSEMBLY PART No. 22124 SEAL 7 1/2 " O.D. 6 3/4 " I.D. GLASS FILLED TEFLON MOLYGLASS CHEVRON

THREAD 6.278" I.D. TWO THREADS PER INCH DOUBLE HELIX PACKER SEAL ELEMENT 8 1/4 " O.D. 2 BACK UP RINGS 11784 2 END SEALS 119720 1 MIDDLE SEAL 113945

LINER PACKER, BROWN TYPE C.P.H., 7" x 9 5/8 " 53.5 lb/ft WITH 20' POLISHED BORE RECEPTABLE EXTENSION 8.250"O.D. 7.250" I.D. 6.062" BODY I.D. (6.516" O.D. FLOAT NUT) WITH 3' EXTENSION OF PAKER BODY (NIPPLE) AND HIGH PRESSURE P.B.R. EXT. BODY SEALS, 7" VAM THREADS THROUGHOUT. 7" VAM PIN DOWN. 4140 HT 110000 MIN YIELD BODY, 140000 PSI MIN YIELD EXT., NIPPLE TO EQUAL BURTS AND COLLAPSE OF BODY.

0.73

0.88

SHEAR PINS 3 x 7/16 " 13,200 lbs

SHEAR PINS 9 x 7/16 " 39.000 lbs

0.71 0.67 2.39 .56 .44 .56 .44 .56 .44 .56 .44 .56 .44 .56 1.28 2179/11

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PACKERS: TIW SN-6 RETRIEVABLE TIE-BACK PACKER

1.1

A TIW SN-6 retrievable tie-back packer will be run in the event that the 7” or 5”/4 1/2” liner lap is leaking.

1.2

In the case of a 7” liner lap leak, make 6” bit and tandem 9 5/8”/7” scraper run, spacing out so that the 9 5/8” scraper will clean up the tie-back packer setting area. Include on the same assembly the polish bore mill, spacer sub and PBR top dressing tool, as per drawing on page 3. Space the mills to suit the length of PBR in place on the liner hanger. The teeth of the PBR top dressing mill should be filled with bakerlock before going in hole so that a wear pattern can be seen when the tool is pulled. Set down 2000 - 4000 lb at 50 RPM for four minutes only. Pick up and pump a viscous pill to clean up cuttings. ENSURE POLISH BORE MILL IS CORRECT OD TO FIT PBR IN PLACE. POH.

Note: When cleaning out and dressing the PBR, DO NOT: a) Rotate in one place for longer than 5 minutes. b) Slack off more than 10,000 lbs on top of the PBR. 1.3

Log 7” CBL/VDL/GR/CCL. Note that if no 9 5/8” CBL has been logged previously then the tools should be centralised to allow both casings to be logged in one run. (This procedure is acceptable for a near vertical well).

1.4

If required, run gauge ring/junk pusher to top of the PBR. Gauge ring to be mid way between packer OD and casing drift diameter.

1.5

Check: a) That the packer, seal nipple and PBR dimensions correspond with the drawing in this section. b)

That the seal nipple is the correct item to fit the PBR in place, i.e. length and seal OD.

c)

That the PBR on top of the tie back packer is the correct length, OD, bore and pressure rating for the application required and conforms with programme requirements.

d)

The size and number of shear pins for: 1. Setting the slips. 2. Securing the inner release sleeve.

1.6

e)


f)


g)

Running tool pack off seals fit RPOB profile below PBR.

Make up the running assembly. Ensure sufficient DC and HWDP are used to overcome the pump out force. 7” tools pump out force is approx 14,500 lbs per 500 psi internal pressure.

1.7

RIH slowly with the tie back packer (minimum 2 min/stand).

1.8

Check string weights up and down.

1.9

Circulate for a short period above the PBR. With the pump running slowly, carefully stab into the PBR. Stop the pump as soon as a pressure increase is observed and release pressure. Ensure DP remains open. Stab fully into the PBR - do not allow the packer to take more than 5000 lbs weight.

1.10

Test down the drillpipe to 2500 psi for 15 mins.

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1.11

With the drill pipe open, test down the annulus to 1500 psi for 15 mins. If liner lap is leaking, do not exceed the leak off pressure at the 9-5/8” casing shoe.

1.12

Set the packer with ± 40,000 lbs weight. Pick up on setting tool and pull up to ± 5,000 lbs. Set down ± 40,000 lbs again.

1.13

With drillpipe open, test down the annulus to 1500 psi for 15 mins.

1.14

Test down the drillpipe to ± 2500 psi for 15 mins.

1.15

Pick up until ± 5000 lbs weight is still on the setting tool. Release running tool with 15 turns to the right.

1.16

Pressure test the complete liner overlap to 3500 psi for 15 min against the pipe rams. Proceed carefully as in a leak off test in case there is a leak past the packer down the overlap.

1.17

POOH.

1.18

An inflow test with a packer may be considered. (Refer to Section 3560/GEN.)

Any variations to the above test pressures will be advised in the Drilling Programme.

BP EXPLORATION


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P.B.R. TOP DRESSING MILL & POLISH BORE MILL T.I.W. EQUIPMENT - 7" LINER

41/2 "REG PIN

2.00'

81/2"

0.90'

DRESS MILL

63/8" 41/2 "REG PIN 41/2 "REG BOX

61/4"

1.60' SPACER SUB 6.00'

41/2 "I.F. PIN 41/2 "I.F. BOX

61/4" 2.30' 4.30'

711/32"

31/2 "I.F. PIN

2179 / 7

BP EXPLORATION


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PACKERS: TIW SN-6 RETRIEVABLE TIE-BACK PACKER 4 1 / 2 " I.F. BOX

LINER TOP STRAINER 7.375" LG-6 SETTING COLLAR

TIE BACK SLEEVE 6FT.

8 1/4 "

101" 8' - 5'

RUNNING THREADS 6.250" RUNNING TOOL

RPOB NIPPLE

RETRIEVABLE PACK-OFF BUSHING 8 1/4 "

5.6' SLICK JOINT 15' APPROX. 8 1/4 " 8 1/8 " 8 1/4 " 7 9/16 "

7.375" 7.3" 4.6'

2179/8

BP EXPLORATION


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PACKERS: BRIDGE PLUG SETTING - GENERAL

1.

In wells where the deviation is less than 50° bridge plugs will be set on electric wireline, above 50° bridge plugs will be set on drill pipe. When setting bridge plugs on drill pipe, only hydraulic setting tools will be used and NOT rotary set running tools.

1.1

Prior to running the bridge plug the casing should be cleaned with a casing scraper. If the bridge plug is to be set on wireline a gauge ring/junk basket will be required in addition to the scraper trip.

1.2

The wireline setting tool uses explosives. Radio silence and Rig Floor safety precautions will therefore be required.

1.3

When ordering bridge plugs it is necessary to state whether it is for wireline or mechanical set, as the top slips are different.

1.4

The three most common bridge plugs used by BP are: 1. 2. 3.

Baker Model “N-1” Pengo SV Halliburton EZ Drill

The Baker plug is the most widely used, it is also the only one with an hydraulic setting tool Baker model “J”. This setting tool can be used to set other bridge plugs that use the Baker “E-4” wireline pressure setting tool - refer to Section 3. 2.

WIRELINE SET The wireline bridge plug is run and set using the appropriate Wireline Pressure Setting Assembly and Wireline Adaptor Kit (refer to page 3). i)

Remove metal shipping band from around lower slip.

ii)

Make up to wireline - measure distance between centre line of rubbers to CCL.

iii) Run in relatively slowly stopping every 300m and pulling up 10m to check cable is not over running the setting tool. iv) Run down not more than one collar below setting depth and log up at least five collars. Make a print of the correlation log and check that the collars are on depth with the reference log. If depths are at variance adjust the depth, make another print and check depths. v)

Run back down being careful not to go below previous lowest depth, pull up checking collar and tension, recording both on film. Stop at setting depth and shift CCL on film to indicate CCL depth at time of setting. Set the bridge plug.

vi) When setting bridge plugs on wireline, never run down closer than 5m above open perforations when correlating depths, unless advised otherwise by the Drilling Office. 3.

MECHANICAL SET (HYDRAULIC) Where the deviation is greater than 50° bridge plugs will be run and set using the Baker Model “J” Hydraulic Setting Assembly. Under no circumstances will rotary set tools be run. The Model “J” tool is a direct replacement for the Model “E-4” Wireline Pressure Setting Assembly, such that any plug that has an adaptor kit compatible with the size 10 or 20 model “E-4” Wireline Pressure Setting Assembly can be run on the Baker Model “J” Hydraulic Setting Assembly.

BP EXPLORATION


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Operation As previously stated the Model “J” Hydraulic Setting Assembly uses the same Adaptor Kit used with the Wireline Pressure Setting Assembly. The adaptor kit is made up on to the packer, and the Setting Assembly is made up onto the Adaptor Kit. The assembled tools are then ready to run in the hole. Make up bridge plug to setting tool as follows: i)

Take care when transferring assembled unit to the rig floor as the slip assemblies are very brittle and easily damaged.

ii)

Screw adjuster sub onto setting mandrel of type “J” setting tool and lock in place with grub screw provided.

iii) Screw setting sleeve onto cross link sleeve of type “J” setting tool (chain tong tight). iv) Make up release stud to tension mandrel. v)

Holding top slips in position, lift up bridge plug, locate lock spring on the end of the tension mandrel with the slot on the adjuster sub and make up bridge plug to setting tool being careful to keep top slips aligned with setting sleeve. Final make up should be snug.

Note: Refer to page 5 for parts list. 3.2

Setting Procedures i)

With bridge plug on depth pump down a 1 7/16” dia Kirksite ball to its seat in the Support Sleeve of the setting assembly.

ii)

Apply 1000 psi pressure to shear the shear screws in the Support Sleeve. The support sleeve in its sheared position closes off the top sub ports diverting the pressure to the Pistons. While the setting mandrel of the adaptor kit, which is attached to the lower end of the plug remains stationary, the Adaptor sleeve of the adaptor kit is forced downwards and hence the upper plug body downward. Thus squeezing the plug forcing the slips and packing element to set and pack off (refer to the diagram on page 3). Approximately 1500 psi is required to set the upper slips using a 2 cylinder tool and 1000 psi using a 3 cylinder tool.

iii) After the top slips are set, the setting and release can be completed either by applied tension, pump pressure or a combination of both. (See tables on page 4 for the various combinations). iv) Once the release stud has been sheared the Adaptor Kit and Setting Assembly can then be pulled out of the hole. As the upper piston moves downwards to the Cylinder Connector, ports in the lower end of the Upper Cylinder are uncovered, allowing the fluid in the DP to freely drain when POH.

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J B

Section

F

1

27 SIZE 10 ONLY

2 3 4 L

6 8

5 6 7

C

8 26 8 9 10 11 12

D

13 10

8 M

10 6

A

13 G 8 14 15 D

D

17 11 18 19 20 21 22 23 24

H E

25

BASED ON T/W DWG 181-558

8 9 11 12 10

NM 13 G 25

8 10 D

12

N SIZE 10

10 13

RUNNING-IN

3 CYLINDER ASSEMBLY

RELEASED

2179/51

BP EXPLORATION


TOOL O.D. 3.50 3.71

SETTING ADAPTOR SLEEVE ROD 052-5307-092 052-5307-094

4.75

052-5307-097

5.61

052-5307-095

052-5307-093

052-5307-096

A

B

C

3.50

3.00

9.56

4.20

3.75

9.56

4.75

4.00

9.50

5.25

4.75

9.56 23.25 13.00

6.09

052-5307-099

6.09

5.25 18.12

6.96

052-5307-060

6.96

6.00 15.68

7.71

052-5307-061

7.71

6.62 13.12

8.12

052-5307-158

8.12

6.75 13.12

8.71

052-5307-062

8.71

7.50 12.18

9.50

052-5307-063

9.50

8.00 11.50

11.56

052-5307-071

11.56 10.50 11.62

12.00

052-5307-064

12.00 10.50 11.62

052-5307-098

D

E

5215/GEN

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:

4 of 5

20.12 10.00

THIS END ATTACHES TO PENGO OR GEARHART 3 1/2 " O.D. W.L.P.S.A. OR BAKER ADAPTER KITS

F 3/4

- 16

N.F.

2.43 2.81

1 - 1/8 - 12 N.F.

C 33.68 18.00

1 - 1/8 - 12 N.F.

ALL DIMENSIONS ARE SHOWN IN INCHES 1

:


4.24 5.34

Section

A B D

SETTING SLEEVE ADAPTOR ROD

052-5307-042 ASSEMBLY COMPLETE - BAKER No. 10 ADAPTOR KIT - ADAPTS FROM BAKER

E

10 W.L.P.S.A. TO PENGO SETTING ADAPTERS - INCL. ITEMS 2,3,4 AND 5 2

052-5307-043 ADAPTER SLEEVE

3

066-0350-126 LOCK RING FOR SETTING SLEEVE

4

052-5307-044 ADAPTOR ROD

5

066-0350-127 LOCK NUT FOR ADAPTER ROD

6

066-0350-156 ASSEMBLY COMPLETE - BAKER No. 20 ADAPTER KIT - ADAPTS FROM BAKER

7

066-0350-157 ADAPTER SLEEVE

8

066-0350-158 ADAPTOR ROD

F

20 W.L.P.S.A. TO PENGO SETTING ADAPTERS - INCL. ITEMS 3,5,7,8 AND 9

9

SOCKET HD. SET SCREW - 5/16- 18 x 3/8 LONG

7

2 16.63"

9

8.25" 6 3

1

8 3

3.25"

4

3.25"

5

BAKER 10 ADAPTOR KIT

5 BAKER 20 ADAPTER KIT

2179 / 57

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PARTS LIST ITEM 1 2 3 4

6 7

TOP SUB O-RING SUPPORT SLEEVE O-RING SHEAR SCREW HDLS BRASS SHEAR SCREW RD HD BRASS CONTROL SUB CONTROL LATCH

8

O-RING

9

UPPER PISTON

5

No. REQ'D

DESCRIPTION

3 CYLINDER 2 CYLINDER 3 CYLINDER 2 CYLINDER

10

O-RING

11

CYLINDER

12

UPPER PISTON ROD

13

CYLINDER CONNECTOR

14 15 16 17 18 19 20 21 22 23 24 25

LOWER PISTON LOCK PIN HEX SOCKET SET SCREW PISTON ROD CYLINDER HEAD HEX SOCKET SET SCREW LINK RETAINING RING HEX SOCKET HEAD SCREW ANNEALED STEEL SHEAR SCREW CROSS LINK CROSS LINK SLEEVE SETTING MANDREL

26

O-RING

27

KIRKSITE BALL

20 01-47850-00 WW-8325-H40 01-47851-00 WW-8335-H40 — 12-24 x 1/2 Lg 01-47852-00 01-86611-00 (6) WW-8334-H40 (9)

1 2

01-61980-00

02-08088-00

SEE SIZE

(3) WW-8210-H40 (6)

(2) WW-8216-H40 (4)

01-60016-00

01-57543-00

01-86577-00

01-47857-00

01-57558-00

01-47858-00

01-61981-00 01-51582-00 1 /4 -20 x 3/8 Lg 01-60620-00 01-23477-00 — 01-23478-00 1 /4 -20 x 3/8 Lg 5 /16 -18 x 3/8 Lg 01-23479-00 01-81142-00 01-83192-00

01-47859-00 01-33451-00 — 01-56892-00 01-20442-00 3 /8 -16 x 1- 1/2 Lg 01-22107-00 1 /4 -20 x 3/8 Lg 5 /16 -18 x 3/4 Lg 01-20523-00 01-81141-00 01-83193-00

1 3 1 1 2 2 1 1 2 CYLINDER

3 CYLINDER 2 CYLINDER 3 CYLINDER 2 CYLINDER 3 CYLINDER 2 CYLINDER 3 CYLINDER

2 CYLINDER 3 CYLINDER

COMMODITY NUMBER 10 01-57552-00 WW-8222-H40 01-57553-00 — 12-24 x 1/4 Lg — 01-57555-00 01-57554-00 (5) WW-8327-H40 (6)

SEE SIZE

2 3 1 2 1 2 1 1 1 1 1 1 1 1 1 1 1 1 2 4 1

WW-8225-H40

—

1- 7/17 O.D.

1- 7/18 O.D.

STRAIN IN POUNDS NECESSARY TO SET A PACKER RUN ON MODEL 'J' HYDRAULIC SETTING TOOL 2 CYLINDERS 3 CYLINDERS SIZE 20 SET WITH SIZE 10 SET WITH SIZE 20 SET WITH SIZE 10 SET WITH 7 7 1" DIA 35,000 LBS /8 " DIA 35,000 LBS 1" DIA 35,000 LBS /8 " DIA 35,000 LBS RELEASE STUD RELEASE STUD RELEASE STUD RELEASE STUD PUMP PRESS STRAIN LBS PUMP PRESS STRAIN LBS PUMP PRESS STRAIN LBS PUMP PRESS STRAIN LBS PSI OF FORCE PSI OF FORCE PSI OF FORCE PSI OF FORCE 1000 24500 1000 34000 1500 25100 1500 35000 1250 21800 1250 28600 1750 23450 1750 33000 1500 19200 1500 23300 2000 21800 2000 29000 1750 16500 1750 18000 2250 20150 2250 26000 2000 13900 2000 12700 2500 18500 2500 23000 2250 12200 2250 7400 2750 16850 2750 19000 2500 8600 2500 2100 3000 15200 3000 16000 2750 5900 2600 0 3250 13550 3250 13000 3000 3300 3500 11900 3500 10000 3250 600 3750 10250 3750 6000 3500 0 4000 8600 4000 3000 4250 6950 4200 0 4500 5300 4750 3650 5000 2000 5303 0

2179 / 58

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PACKERS: EZ DRILL-SV SQUEEZE PACKERS

INTRODUCTION (See Figures 1 and 2) Fluid movement through EZ Drill-SV Squeeze Packers is controlled with a pressure-balanced “Sliding Valve” instead of a spring-loaded back-pressure valve. Operated by reciprocation of the string, the valve may be opened or closed, as desired, before and after squeeze cementing. Fluid movement through the valve is closed (up) the packer is sealed against fluid movement in either direction. When the valve is open (down) fluid may be pumped through the packer or pressure may be relieved from below it. When the valve is open, an unrestricted fluid passage is provided through side port in the tool. With little external surface exposed to cement slurry, the sliding valve is not likely to be cemented in place.

2.

APPLICATION EZ Drill-SV squeeze packers can be used: a) b)

3.

in squeeze cementing (refer to Section 3650/GEN and diagram on page 4). as a bridge plug (refer to diagram on page 5).

OPERATION i)

Make Up Packer on Setting Tool (refer to diagram on page 6) Insert lower mandrel (stinger) of setting tool into packer and make up coupling ring on tension sleeve. Make up the setting tool on the string and lightly lubricate stinger before inserting in packer. The packer is furnished with the sliding valve in the closed (up) position.

ii)

Running In Well Normal care should be exercised in running the packer into the well to avoid sudden stopping of the string. Clockwise rotation of the tubing string must also be avoided.

iii)

Setting Packer The EZ drill SV and EZ drill SV open hole packers are set with 35 turns righthand rotation followed by an upward pull to part the tension sleeve. Righthand rotation of the setting tool mandrel moves the setting sleeve downward to set the top slips. A slow, intermittent pull applied to the string will then set the packer firmly before the tension sleeve parts. After parting the tension sleeve and before rotating additional turns to release the setting sleeve, considerable string weight can be set down against the packer without fear of damaging the packer. This procedure is recommended to aid in setting the packer since the string weight is transfered through the setting sleeve to the top slips at this point. This causes any weight in excess of the tension sleeve strength to aid in further compressing the packer rubbers and setting the slips.

iv)

Testing String Method 1 After setting packer but before releasing the setting sleeve set the maximum permissible string weight on the packer and apply pressure (500-1000 psi) to the casing. The packer mandrel will be moved to its lowest position, closing the sliding valve. Pressure can now be applied to the string without further manipulation. If desired, pressure can be held on the casing. This method permits string weight to be set on the packer and is especially useful in holes where it is difficult to raise the string only a few inches.

BP EXPLORATION


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PACKERS: EZ DRILL-SV SQUEEZE PACKERS Method 2 This method is similar to No.1 but can be used where pressure cannot be applied to the casing. String weight can be set on the packer while testing. After setting the packer but before releasing the setting sleeve lower the string to establish bottom. Raise the string to its neutral position (full string weight on weight indicator). Raise string the distance shown below. Apply about 1500 psi to string to move the mandrel down, weight on the packer and pressure test.

Packer Size

Raise String

4 1/2”, 5”, 5 1/2” 7”, 7 5/8”, 8 5/8” 9 5/8”, 10 3/4”, 13 3/8”

3 - 6” 3 - 8” 3 - 9”

Note: When using method 1 or 2 string testing pressure must be limited so that pressure differential applied across the packer mandrel does not exceed the maximum listed below. String testing pressure must therefore be limited so that the combination of applied pressure and hydrostatic pressure placed on top of the packer after setting does not exceed these maximums. 4 1/2”, 5” and 5 1/2” - 7000 psi maximum 7”, 7 5/8” and 8 5/8” - 8000 psi maximum 9 5/8”, 10 3/4” and 13 3/8” - 9000 psi maximum v)

Release Setting Sleeve It is necessary that the setting sleeve on the setting tool be released to move upward in order to make sure the stinger can go into the packer far enough to reach the sliding valve. This is accomplished by rotating the string 20 turns. This disengages ring so that the setting sleeve is free to move upward out of the way when the setting tool is set back down on the packer. CAUTION String weight will be transferred through the setting tool stinger and the packer sliding valve to the lower end of packer mandrel when setting down weight after releasing the setting sleeve. Breakage of the mandrel might possibly result if excess weight is set down at this point. For this reason, weight in excess of the tension sleeve strength should never be applied to the packer after releasing the setting sleeve. Severe shock load also should not be created by dropping the string onto the packer as this too could result in breaking the packer mandrel.

vi)

Operations of Sliding Valve The sliding valve is opened by setting weight on the packer. The valve is closed by picking up on the string. The sliding valve is positively opened and closed by string reciprocation. In the closed position the collapsible fingers at the upper end of the sliding valve are expanded into a recess in the bore of the packer mandrel. As the string is lowered, the end of the stinger contacts the shoulder on the I.D. of the valve below the fingers and pushes the valve down to the open position. The fingers of the valve move out of the recess into the mandrel bore, collapsing behind the upset on the stinger. Upward movement of the string pulls the sliding valve closed. As the fingers expand back into the recess, the stinger is released and withdrawn from the packer. The valve remains locked in the closed position.

BP EXPLORATION

DRILLING MANUAL SUBJECT: vii)

Section

:

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:

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PACKERS: EZ DRILL-SV SQUEEZE PACKERS Converting to Bridge Plug An EZ Drill SV Squeeze Packer may be converted to a bridge plug for setting on wireline by installing a Bridging Plug in the packer bore in place of the internal seal.

viii)

Suggested Drilling Technique - Drillable Squeeze Packers and Bridge Plugs Best technique for drilling squeeze packers and bridge plugs will vary with available equipment but in general the following is suggested as a guide when drilling with rotary equipment. Bit - short or medium tooth hard formation. Rotary Speed - 75 to 120 RPM. Weight of Bit -

Apply 5000 - 7000 pounds until the top end of the packer mandrel is drilled (4”5”) and weight can be applied across the full bit diameter, then increase to 2000 - 3000 pounds per inch of bit diameter to drill out the remainder of the packer (with 4 3/4” bit use 9500 - 14000 pounds).

Drill Collars - as required for weight and bit stabilization. A junk basket should be placed above the bit when normal circulation is employed. Spudding the string or variations in rotary speed and bit weight should be employed to help break up the metal parts and to re-establish bit penetration should it cease while drilling.

BP EXPLORATION


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EZ DRILL SV SQUEEZE PACKER

TENSION SLEEVE (BRASS) MANDREL (MEDIUM HARDNESS CAST IRON) LOCK RING HOUSING (SOFT CAST IRON) LOCK RING (ALUMINIUM) INTERNAL SEAL (RUBBER WITH BRASS SHOES) TOP SLIPS (HARD CAST IRON) RETAINING BAND (MILD STEEL OR BRASS) WEDGE RETAINING RING (BRASS) TOP WEDGE (SOFT CAST IRON) SCREWS (BRASS) EXPANDING SHOES (BRASS) END PACKER (RUBBER) CENTRE PACKER (RUBBER) END PACKER (RUBBER) ALIGNMENT BOLT (MILD STEEL) PINS (MILD STEEL) LOWER WEDGE (SOFT CAST IRON) SLIDING VALVE (BRASS) LOWER SLIPS (HARD CAST IRON) RETAINING BAND (MILD STEEL OR BRASS) FLUID PORTS VALVE SEAL (RUBBER)

LOWER SLIP SUPPORT (SOFT CAST IRON)

2179/52

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802.3543 SETTING TOOL 9 5/8 " – 13 3/8 " EZ DRILL SV SQUEEZE PACKERS

2 7/ 8" OD 8 RD EUE TBG THD 9.80"

5.06" OD 7.00"

3

ADAPTER – 802.35435 “O” RING – 1 REQUIRED – 70.33976 TO REMOVE TOP ADAPTER HOLD BACK-UP HERE RELEASING SLEEVE CAP – 802.35438 “O” RING – 1 REQUIRED – 70.33976 SET SCREW – 1 REQUIRED – 70.44836 DRAG SPRING RETAINING RING – 802.35432

8.87" 5.00" OD 6.87" OD 27.8" 2.875" OD

RELEASING SLEEVE – 802.35432 DRAG SPRINGS – 3 REQUIRED 1

4.69" OD

ARCH DIAMETER 5 RELEASING RING – 802.35433 “O” RING – 1 REQUIRED – 70.34034 SET SCREW – 4 REQUIRED – 70.44791 DRAG SPRING BODY – 802.35436

1.62" ID

SETTING SLEEVE BODY – 802.35452 BUSHING – 802.35437

46.25"

SETTING SLEEVE – 802.35457 UPPER MANDREL – 802.35434 6.06" OD

“O” RING – 1 REQUIRED – 70.33872 “O” RING – 1 REQUIRED – 70.34047

5.75" OD

23.12"

3.198" OD

2

COUPLING RING – 802.35455 SLEEVE SHIELD – 802.35456

1

CASING SIZE & WEIGHT 9 5 /8" 29.3-71.8 10 3 /4" 32.75-71.1 11 3 /4" 38-60 13 3 /8" 48-72

2.25" OD 1.62" ID

LOWER MANDREL – 802.34539

DRAG SPRINGS PART NO 690.908 690.909 690.910 690.911

5 ARCH DIAMETER 10.0" 11.5" 12.5" 13.75"

1

DRAG SPRINGS ARE NOT ASSEMBLED ON SETTING TOOL

2

TO SET 9 5/ 8" AND LARGER EZ DRILL SV SQUEEZE PACKERS WITH CASING ALIGNMENT TOOL ADAPTER KIT USE MANDREL 802.35400

3

OPTIONAL ADAPTERS 802.35492 – 4 1/2 " IF DRILL PIPE 802.36493 – 4 1/2 " EXTRA HOLE DP 802.35443 – 3 1/2 " IF DRILL PIPE 802.35496 – 2 7/8 " IF DRILL PIPE

PACKAGE SHIPPING WEIGHT – 225LBS

2179/63

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MODELS ‘A’ AND ‘E’ SLEEVE VALVE RETAINERS MODELS ‘SVA’ AND ‘SVE’ BRIDGE PLUGS (WIRELINE AND TUBING SET) SLEEVE VALVE RETAINER (SHOWN WITH MODEL ‘A’ PACKING)

SV BRIDGE PLUG (SHOWN WITH MODEL ‘E’ PACKING)

B

MECH TOP SLIP

D N

C

P

A E F G

K

K

F E L

J

M

A

H

B A

TOOL O.D. A B 3.50 3.43 3.71 3.62 4.24 4.20 4.75 4.64 5.34 5.25 5.61 5.56 6.09 6.00 6.96 6.84 7.71 7.59 8.12 8.00 8.71 8.59 9.50 9.43 11.56 11.50 12.00 11.87

ALL DIMENSIONS ARE SHOWN IN INCHES C 2.31 2.31 2.59 2.31 2.81 2.81 2.68 2.75 2.93 3.06 3.37 3.68 3.87 3.87

D 1.68 1.68 1.62 1.93 2.12 2.18 2.37 2.75 2.87 2.75 2.87 3.12 2.90 3.25

E F G 3.43 3.43 3.43 3.68 3.68 3.68 4.21 4.21 4.21 4.68 4.68 4.68 5.28 5.28 5.28 5.59 5.59 5.59 6.03 6.03 5.93 6.87 6.87 6.87 7.62 7.62 7.62 8.00 8.00 7.87 8.62 8.62 8.62 9.46 9.46 9.46 11.43 11.43 11.43 11.87 11.87 11.87

H 2.12 2.12 2.75 3.00 3.68 3.68 4.12 4.62 5.12 5.68 5.68 6.75 9.00 9.00

J 1.345 1.345 1.345 1.345 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00

K 12.21 12.21 12.21 12.81 15.37 15.37 20.37 20.37 21.81 22.31 22.31 24.00 23.75 23.75

L 19.34 19.34 19.34 19.59 22.93 22.93 27.93 27.93 31.25 31.56 31.56 31.56 31.56 31.56

M N 16.21 3.43 16.21 3.62 16.21 4.18 16.46 4.62 30.37 5.25 20.37 5.56 25.37 6.06 25.37 6.93 28.68 7.64 29.00 8.04 29.00 8.59 29.00 9.43 29.00 11.50 29.00 11.93

P 2.93 2.93 3.12 3.12 3.12 3.12 3.75 4.12 4.50 4.50 4.50 4.50 4.12 4.50 2179/53

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PACKERS: "BOBCAT" RETRIEVABLE BRIDGE PLUG

GENERAL DESCRIPTION The Bobcat Retrievable Bridge Plug is a packer element type of plug using one set of compression set slips to anchor the plug against pressure forces from above and below. The packer elements expand and contact the casing only when the plug is set. This allows fluid to bypass around the tool as well as through it for smooth trips in and out of the hole and allows the packer element to reach setting depth in new condition. The single slip design requires only compression slips to hold differential pressure loads from above and below. With a pressure differential from above, the slips operate as simple compression slips. With pressure differential from below, the load is taken on the back side of the slips. While the pressure tries to pump the tool up hole, it also forces the slip cone down under the slips, thus maintaining the slips set. When the packer elements are expanded, they exert a force that tends to hold the slip cone under the slips. This allows a tension load to be exerted on the plug to determine if it is set. The plug is set and released with right hand rotation. This allows washing down to the tool with right hand rotation to get onto the fishing neck and to mill up any junk above the tool. The only left hand torque required is 1/4 turn at the tool to remove the running tool from the plug. The Bobcat Retrievable Bridge Plug can be set and released any number of times during a trip in the hole.

2.

DESIGN FEATURES

Settable Packer Elements Packer elements are run and retrieved in a relaxed condition, thereby eliminating possible damage due to perforations or burrs inside the casing. The elements are expanded when the plug is set and provide a positive seal as long as the tool is set. “Bobcat” Slip Mechanism This system utilises a compression set slip arrangement that provides restraint against differential pressure forces above or below the plug. This eliminates tension slips that can accidentally set while retrieving and often are difficult to release. Right Hand Setting and Releasing The plug is set and retrieved with only right hand rotation. The only left hand torque applied is to release the overshot from the plug after setting. This design permits rotating down to wash off sand and debris when retrieving the plug. Large By-Pass Area Fluid by-passes through tool and around tool while running or retrieving. This provides easier running and retrieving by eliminating floating action of cup type plugs. Balanced Type Equalizing Valve Equalizing valve is balanced so that differential pressure changes have no effect. Valve is opened easily when tagging plug and permits pressure equalization before the plug is released. Shallow Setting Plug may be set shallow by unjaying with right hand rotation then applying left hand rotation to set elements.

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OPERATING INSTRUCTIONS

Attaching Running Tool - The Running Tool cannot be latched onto the Bridge Plug by hand because of the strong spring fingers in the Finger Bowl. The Running Tool must be assembled on the Bridge Plug. 1.

Unscrew Port Mandrel assembly from Upper Mandrel.

2.

Place Finger Bowl and Mill Shoe assembly over Trap Sleeve.

3.

Screw Port Mandrel assembly back into Upper Mandrel. Make up.

4.

Drive open Equalizing Valve with hammer and wood block.

5.

Place Valve Ring in position (5 1/2” and 6 5/8” - 7” - 7 5/8” Tools).

6.

Screw upper Running Tool assembly onto Finger Bowl. Make up.

Operation of Running Tool - The Running Tool is the means of connecting the Bridge Plug to the tubing string. It is screwed onto the end of the tubing string or onto the bottom of the tool that is to be run above the Bridge Plug. The Bridge Plug is latched into the Running Tool. Together with providing a connection to the Bridge Plug, the Running Tool also opens and closes the Equalizing Valve on the Plug and provides a Mill Shoe to cut up any junk or cement that might be on top of the Bridge Plug. The Running Tool is latched onto the Bridge Plug by means of two lugs in the Running Tool that engage a “J” Slot on the fishing neck on the Bridge Plug. It is latched onto the Plug by pushing it on and rotating to the right. It is removed by pushing it down, then picking up, holding left hand torque. The spring fingers on the Running Tool perform two functions: 1.

Close equalizing Valve on Bridge Plug.

2.

Keep Running Tool lug up in the top part of the “J” Slot while coming out of the hole.

A shoulder in the Running Tool opens the Equalizing Valve when the Running Tool is latched onto the Plug. The spring fingers close the Equalizing Valve as the Running Tool is pulled off of the fishing neck. The Running Tool lugs must be in the bottom of the “J” Slot for the Running Tool to disengage from the Bridge Plug. When coming out of the hole, the spring fingers keep the lugs in the top part of the jay so that the Running Tool cannot be accidentally disengaged from the Plug. To latch onto the Plug, and in some cases to get off of the Plug in the hole, the spring fingers in the Running Tool must be forced down over the Detent Ring on the Port Mandrel of the Plug. About 8000 lbs of weight is required to force the fingers over the detent. Note: The detent ring should be removed from any plug that is to be set where less than 8000 lbs of weight is available to set on it. A thread protector should be screwed on in place of the Detent Ring.

Running in Hole - The Bobcat Retrievable Bridge Plug can be run in the hole at a good rate of speed because of its packer element design. Do not let the tubing be turned to the right going in the hole. A slight turn put in the tubing a number of times can accumulate enough turns to set the plug. The tubing should be picked up several feet about every five stands of pipe while going in hole. Picking up will “resafety” the tool in case the tubing has been turned to the right. Setting Packer - If a packer is being run with the bridge plug, safety the packer before setting plug. To set plug, move downhole slowly while rotating tubing to the right; three to four turns at the tool are required. As soon as the plug takes weight, stop rotating tubing and set down from 10,000 to 15,000 lbs of weight on the plug to set the packer elements.

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Releasing Packer - With 1000 lbs on the plug, turn tubing to the left (1/4 turn required at tool) and pick up. As the Running Tool pulls off of the fishing neck it closes the Equalizing Valve. This may require as much pull as 5000 lbs. If a packer is run with the plug, a check should now be made to make certain the plug and not the packer is set. To do this, pick up and safety packer and then go downhole to tag the plug. If weight is slacked off, the plug is set. Come off again as described above. The tool is now set and will hold pressure from above or below. Pressure may be applied from above to make certain the packer elements are sealing. This is recommended when the tool is set with a small amount of weight. The pressure from above further compresses the packer elements and traps this movement, thus creating a better pack off.

Retrieving Packer - Tag tool with 5000 to 10,000 lbs. The Running Tool automatically engages the fishing neck and at the same time opens the Equalizing Valve. If sand, cement, or junk has settled down on top of the tool, the Running Tool can be rotated down while circulating to wash the debris away. The Mill Shoe on the bottom of the Running Tool cleans the hole down to the packer elements. The tubing can be rotated after the Running Tool has engaged the Fishing Neck, since the plug mandrel is free to rotate. After engaging the fishing neck, pick up with right hand torque and pull 3000 lbs. Rotate to the right holding a strain in the tubing until weight drops off. Continue rotating 15 turns while moving up hole. The tubing must be moving up hole while it is turned to safety tool. Pick up ten feet then lower tubing down to a spot below where the tool was set to be certain that the tool is safetied up. The tool can now be retrieved or moved to another location and set again.

Detaching Running Tool from Plug - The Running Tool and part of the Bridge Plug must be disassembled to remove Running Tool from Plug. 1.

Unscrew Finger Bowl from upper Running Tool assembly.

2.

Unscrew mandrel in plug by turning Running Tool upper assembly and backing up on lower end of Setting Mandrel. The plug mandrel may break in any one of three places. a)

b)

c)

Neck Unscrews from Port Mandrel 1.

Pull off upper Running Tool assembly with neck. Remove neck.

2.

Remove Equalizing Valve.

3.

Unscrew Port Mandrel from Upper Mandrel.

4.

Remove Finger Bowl and Mill Shoe assembly.

Port Mandrel Unscrews from Upper Mandrel 1.

Remove Upper Running Tool assembly with neck and Port Mandrel assembly.

2.

Disassemble Upper Running Tool assembly from neck.

Upper Mandrel Unscrews from Setting Mandrel 1.

Unscrew Element Retainer from Packing Mandrel. Put back up on Spline Housing.

2.

Pull upper part of plug from lower part.

3.

Put back up on Upper Mandrel. Unscrew plug mandrel by turning Running Tool.

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PACKERS: "BOBCAT" RETRIEVABLE BRIDGE PLUG 4.

Disassemble as described above.

Shallow Setting - The Bobcat Retrievable Bridge Plug can be set at a shallow depth by setting the packer elements with left hand torque. Set tool as described. With tool set and before coming off, torque tubing to the left. Enough torque can be applied with a 36” pipe wrench to set the packer with no danger of backing off any tubing connections. Release packer in usual manner. If possible, pressure should be applied above the tool to check its seal and to tighten the packer elements.

Note: The Detent Ring (located on the Port Mandrel of the Plug) should be removed from any plug that is to be set shallow where the tubing weight is less than 8000 lbs. The Detent Ring will not allow the Running Tool to detach from the Plug downhole when an insufficient amount of weight is available.

Item No.

Description of Main Parts

1 3 5 7 8 10 13 16 17 19 20 23 27 28 29 30 33 37 39 41 43 47 48 49 51 58

Neck Port Mandrel Equalizing Valve Upper Mandrel Trap Sleeve Trap Skirt Element Retainer Element Packing Mandrel Spline Housing Cap Spline Housing Free Piston Slip Bowl Sleeve Slip Bowl Assembly Setting Mandrel Pin Driv-Lok Type “A” Slip Rein Friction Housing Assembly Friction Pad Spring Dizzy Nut Assembly Threaded Insert End Cap Setting Mandrel Plug Plug Adaptor Retainer Nut Detent Ring

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5.30 12.8

10.4

3.75 2.50

25.5

4.25 5.70 4.87

45.3 2.8 4.2

5.62 5.00 3.50

77.2 5.87 1.90 5.37 8- 5/ 8" 1.5

SIZE

9- 5/ 8"

7.31

7.62

8.31

8.62

7.12

7.43

8.12

8.43

7.31

7.62

3.31

8.62

3.0 109.1

10.5

WEIGHT

40-49#

43-61# 24-36#

29-40#

7.12

6.7

8-5/ 8" – 1.375 9-5/ 8" – 1.875 7.12

24.8 2.12 8-5/ 8" – 7.31 9-5/ 8" – 8.21 5.40 2.80

2179/64


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PACKERS: ARROW DLT PACKER, UNLOADER AND STORM VALVE

INTRODUCTION The Arrow DLT packer is a compression set packer with hydraulic hold-down. The hydraulic actuated upper slips assure the packer will not move up the hole. Since the packer is run with a separate positive lock unloading valve, rather than an integral bypass, there is no danger of pumping open a balanced equalising valve. The Arrow DLT packer can be used for: i) ii) iii) iv)

Pressure testing casing etc. Temporary well suspension. Inflow tests. Cement squeezes, acidising etc.

The Arrow unloader is a high pressure accessory for the DLT packer, and is run above the packer in the open position. After the packer has been run to the required setting depth, and set as per procedure, the unloader will automatically close. When run above a DLT or other compression-set packer, the unloader is opened by rotating the tubing 1/4 turn and picking up (see Section 5 below). An Arrow unloader should not be used when the packer is run with a storm valve. The unloader can be run with either a lock open/lock closed or automatic J-slot. The standard is the lock open/lock closed J-slot. 2.

PRE-RUN CHECKS Check DLT packer is fully compatible with casing specification and all relevant drilling equipment, wear bushings etc. Check general condition of DLT packer including elements, slips etc. Check operation of J-slot on both DLT packer and unloader. Hydraulic calculations must be performed if the packer will be exposed to pressure. If storm valve is used the top sub must be unscrewed, threads and O-rings inspected, and reconnected hand tight counting the number of turns required to fully engage.

3.

MAKE-UP GUIDELINES Placing the DLT packer, unloader, and storm valve in the rotary table slips should be avoided and must be avoided if string weight is more than what is needed to set packer. Once made up to the DLT packer, the storm valve top sub must be hand tight only. Note: Packers are heavy and awkward to handle. Do not try to lift or manoeuvre them without the proper equipment or without adequate personnel.

4.

OPERATING PROCEDURE If weight is run below the packer, the unloader will operate as a separate tool to the packer. In this case, as the packer takes weight, the torque is held until the unloader is closed. The unloader will not function until the tailpipe weight is suspended by the packer.


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PACKERS: ARROW DLT PACKER, UNLOADER AND STORM VALVE

Have unloader (if used) in locked open position when running in hole. Avoid right-hand rotation of string when making up pipe as this will set packer and close unloader. Pre test packer as soon as possible below wellhead. If packer functions correctly, release pressure, open pipe rams, unset the tool and continue to run in hole. Run packer 20ft below setting depth recording down string weight. Pick up to setting depth recording up string weight. Apply one turn to the right per 3000ft of depth and hold torque. Lower the drillstring to set packer and slack off weight of string below packer. When setting the packer, right-hand torque should be kept to a minimum. If torque values over 4000ft lbs are required to turn the string, then the string should be turned whilst picking up to setting depth. The packer is now set with unloader closed (if used). 5.

TO OPEN UNLOADER Turn to the right (1/4 turn required at tool) and hold right-hand torque whilst picking up the string to neutral weight at the unloader. Apply ±200psi in string and continue picking up until circulation is established. The unloader is now open and the packer set. To reclose unloader hold right-hand torque and lower string.

6.

TO UNSEAT PACKER Bleed off all pressure from string. Apply ±300psi to annulus to help upper slips on packer retract, then bleed off pressure. Open unloader as described above. Pick up string to unset packer and pause for 5 to 10 minutes to allow elements to relax. Pull out of hole.

7.

STORM VALVE OPERATIONS A storm valve provides a means of disconnecting the drillpipe or tubing close to the surface without tripping the entire string. The storm valve remains closed, providing a secure seal until the drillpipe is reconnected. After setting packer at desired depth, pick up to zero weight at storm valve. Rotate string to the left to release storm valve Note:

No torque should be seen.

After 12 turns the valve is closed, after 21 turns (or number of turns experienced during pre-job checks) the valve is fully disengaged. The storm valve/packer can now be pressure tested up to 3000psi. To retrieve storm valve and DLT packer RIH with valve top sub and carefully tag storm valve with 1000 lbs. During reconnect be prepared to handle pressure from the drillpipe and casing side. Rotate to the right monitoring torque. Note:

Do not apply more than 2000ft lbs torque at tool.

After two to three turns pick up ±3000 lbs to see if threads have engaged. If threads are engaged continue to rotate to the right (valve open after 12 turns) until a total of 20 to 21 turns has been applied. The storm valve is now fully engaged. 8.

MAINTENANCE One of the biggest causes of problems with downhole tools is poor or no maintenance between runs. This is particularly true for storm valves which can easily become plugged and seized with misuse. After each run the packer must be redressed by trained Dowell personnel.

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PACKERS: JOHNSON HURRICANE PACKER

1.

The Dowell Schlumberger Johnson Hurricane Packer is basically a compression set packer with hydraulically actuated, mechanically retractable, upper slips and a pressure balanced bypass valve (refer to Figure 1). It can be used in conjunction with the Hurricane Valve to provide a quick means of securing the well without the need for pulling the bit out of the hole (refer to Figure 2). It may also be used to provide a mechanical barrier while work is undertaken on the wellhead or BOP stack. The valve is a back pressure valve together with a safety joint.

1.1

Setting Procedure

1.2

1.

Make up and RIH the Hurricane Packer and Hurricane Valve to the required depth.

2.

Set the packer by picking up, applying right hand torque and slacking off the weight of drillstring below the packer, holding right hand torque. This unjays the packer, sets the lower slips, closes the bypass valve and expands the rubber elements to effect a seal.

3.

Retrieve the drill pipe and top sub by picking up 2000 - 3000 lbs over the weight of the pipe above the valve and applying left hand torque. This will break the shouldered right hand Acme thread on the Hurricane Valve top sub. Continue rotating left hand to unscrew the top sub until it disengages from the remainder of the valve.

4.

The spring loaded face seal in the Hurricane Valve closes before the top sub disengages from the seal housing. Continue rotating left hand while picking up to prevent damage to threads.

5.

POOH the running string.

Retrieval Procedure 1.

Run back in the hole with the Hurricane Valve top sub on drillpipe.

2.

Install the kelly at surface to check for pressures after re-engaging packer.

3.

Tag the valve with 1000 lbs weight.

4.

Slowly rotate right hand to engage the Acme thread. The thread should shoulder and torque up after 20 - 24 turns.

5.

The face seal valve should be opened by the bypass sleeve before the top sub shoulders. This will allow communication with the fluid below the packer.

6.

Observe any pressures and bullhead down drill pipe if necessary, before unseating the packer.

7.

Pick up the complete weight of the string above and below the valve and move up the hole. This will release the packer and also jay up the packer allowing it to move down the hole if required.

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PACKERS: JOHNSON HURRICANE PACKER

9 5/8 " HURRICANE PACKER

FIGURE 1

2179 / 9

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PACKERS: JOHNSON HURRICANE PACKER FIGURE 2 HURRICANE VALVE

D J B E TOOLSIZE

I

C F

A

43/4

61/4

39.5

42.0

A

9.5

12.3

B

10.3

8.4

C

4.75

6.25

D

1.75

2.25

E

3.00

4.25

F

2.37

3.31

G

1.75

2.25

H

5.37

6.87

I

8.87

11.12

J

FISHING DIMENSION G

H

2179 / 6

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PACKERS: HALLIBURTON RTTS PACKER

Halliburton’s Retrievable Test Treat Squeeze packer is used for: 1. 2.

Formation testing. Inflow tests, acidising, cement squeezes, casing tests, etc.

Refer to Figures 1, 2 and 3. The tool has a type VR safety joint which cannot be re-engaged when disconnected (refer to Figure 4). Hydraulic hold-down slips prevent packer from being pumped up the hole. A circulating valve which can be locked in either open or closed position is provided above the packer. (Lock closed during squeezing to avoid hydraulic opening). Refer to Figure 5. 1.1

Operating Procedure Prior to running in hole, have packer pressure tested, both ends closed, to say 3000 psi (circulating valve locked closed). If a packer is to be set in a liner ensure the packer is fitted with the automatic “J” slot. Have circulating valve locked open and J-slot in dragspring-sleeve in locked position when starting in hole. Avoid right hand rotation of string while making up pipe as this will set packer and close sleeve. Run tool to slightly below desired setting depth, pick-up to setting position and rotate several turns to the right. Only ± 1/2 turn at tool is required but it often is helpful to turn several turns. Holding right hand torque in pipe, slack off weight until mechanical slips set and tool takes weight. Stop movement of pipe, relieve right hand torque by turning to the left (± 1/2 turn per 1000 ft pipe including backlash, however, never more left hand turns than right hand turns given to set tool). As the left hand torque is applied, move the string down until the desired amount of weight is resting on packer. Tool is now set with circulating valve locked closed.

1.2

To Open Circulating Valve for spotting cement etc. Turn to the right and pick up string to neutral weight. Apply pressure in tubing and continue picking up a few inches until circulation is established. After fluid has been pumped to place, slack off until tool starts taking weight, then relieve torque back to the left as explained above while continuing slacking off until proper weight is resting on packer.

1.3

To Unseat Packer Pick-up tubing without turning. Packer unseats more readily if pressure is equalised at the packer before picking up on string. This leaves circulating valve closed so that reverse circulation can be established around packer and tail.

1.4

To Open Circulating Valve for pulling out of hole: Lower pipe, turn to right and pick-up.

1.5

Safety Joint To release safety joint the tension sleeve must be parted first (note tension required before going in hole!), by pulling on string. When the sleeve has been parted the safety joint may be released by holding right hand torque on the tubing while working it up and down. A 10” stroke at tool is required for 8 5/8” and larger size safety joints (7” for smaller sizes). Ten rounds are required to back the nut out, which releases the joint. The smaller sizes require 2, the larger, 3 strokes per revolution. The safety joint cannot be re-engaged.

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PACKERS: HALLIBURTON RTTS PACKER

Maintenance: to be done by Halliburton. Pay special attention to seals on volume tube, circulating sleeve seals. Halliburton operators tend to avoid pressure test on surface, however, we should insist on testing, as experience has shown that leaks are found occasionally. Have circulating sleeve locked closed when testing.

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PACKERS: HALLIBURTON RTTS PACKER FIGURE 1 RTTS PACKER

NOTE : FIRST PART No. LISTED IS FOR 7" SIZE: SECOND IS FOR 7 5/8" - 29.7" - 39" SIZE THIRD IS FOR 7 5/8" - 29.7" - 39" SIZE WHERE ONLY ONE IS LISTED. IT APPLIES TO ALL SIZES 696.57613 - SLIP BODY 70.33976 - "O" RING

DETAIL OF 7 5/8"

693.54 - BOLT

696.08112 - SPACER - 8 REQD 696.08107 - SLIP BOLT - 8 REQD

PACKER AND SPACER RINGS (2 RING ELEMENT) CASING SIZE PACKER RING AND WEIGHT (2 REQD.)

DURO.

O.D.

5.70"

7" - 17* - 29*

696.57384 696.57385 696.57386

75 85 95

7" - 32* - 35* 6 5/8" - 17* - 20*

696.57381 696.57382 696.57383

75 85 95

696.58781 696.58782 696.58783 696.58381 696.58382 696.58383

75 85 95 75 85 95

7 5/8" - 20* - 26.4*

7 5/8" - 29.7* - 39*

SPACER RING (1 REQD.)

DURO.

696.57687 5.50"

6.50"

696.68787

6.20"

696.58687

O.D.

SPACER RING (2 REQD.)

696.57038 696.57048 696.57040 696.57036 696.57049

90 85 90 85 70

7" - 32* - 35* 6 5/8" - 17* - 20*

696.57018 696.57022

90 70

7 5/8" - 20* - 26.4*

696.58083 696.58082 696.58081

90 70 50

6.50"

696.58717

7 5/8" - 29.7* - 39*

696.58018 696.58022 696.58034

90 70 50

6.20"

696.58617

7" - 17* - 29*

7" - 23* - 29*

696.57615 - SLIP RETAINER 696.58615 2 REQUIRED 697.90559 - SLIP SPRING - 8 REQD 696.57074 - SLIP INSERT - 4 REQD 696.58374 696.57305 - SLIP PAD - 4 REQUIRED 696.57073 - SLIP INSERT BODY 969.58673 - 4 REQUIRED 696.57701 - VOLUME TUBE

PACKER AND SPACER RINGS (3 RING ELEMENT) CASING SIZE PACKER RING AND WEIGHT (3 REQD.)

20 REQUIRED 12 REQUIRED

5.75"

5.65"

70.34032 - "O" RING 696.57764 696.58763 - TOP SHOE 696.58764 PACKER RING (SEE CHART) SPACER RING (SEE CHART) 696.57665 696.58765 - BOTTOM SHOE 696.58665 697.90527 - BOLT - 4 REQD 696.57619 - MACHANICAL SLIP BODY 696.58619 697.59612 - SLIP STOP PIN 6 REQUIRED 696.57021 - MACHANICAL SLIP 6 REQUIRED 696.57623 - SLIP RING COLLAR 696.58623

696.57617

801.80545 - DRAG SPRING 16 REQUIRED

5.50"

696.57627 - DRAG SPRING SLEEVE + 696.58627 (STRAIGHT J-SLOT) 696.57702 - LOWER MANDREL

+ DRAG SPRING SLEEVE WITH AUTOMATIC J - SLOT OPTIONAL 696.57626 - 7" 696.58626 - 7 5/8"

70.33974 - "O" RING

PACKER BODY - RTTS 7" - 17* - 35* - 696.577 7 5/8" - 20* - 39* - 696.587

2179 / 54

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PACKERS: HALLIBURTON RTTS PACKER FIGURE 2 RTTS PACKER 6.00"

3.68" DIA

CIRCULATING VALVE ASSEMBLY 696.571 696.5718 2 7/8" OD – 8RD EUE TBG THD

6.60" 12.87" 12.60" 18.87"* TRAVEL

2 15/16" – 10N – 3THD

2.44" ID 4.62" DIA

4 5/32" – 8N – 3THD

8.12" 4 5/32" – 8N – 3THD 7.10" 13.10"*

3" – 10N – 3THD

3.42"

SAFETY JOINT ASSEMBLY 696.5722 70" TRAVEL

17.37"

4.87" DIA

4 1/4" – 4 STUB ACME LH THD

3.46" DIA

119.31" 131.31" * OVERALL

4 1/4" – 8N – 3THD PACKER BODY ASSEMBLY 696.577 – 7" 696.587" – 7 5/8"

6.75"

5.37" DIA

22.68"

2.55" ID 1.995" ID

4 5/32" – 8N – 3THD 7" – 5.75" DIA 7 5/8" – 6.35" DIA 5.42" DIA 3 1/4" – 8N – 3THD 3.25" DIA

6.48"

5.75" DIA 6.35" 37.62" LOWER MANDREL LENGTH

3.56" DIA 2.366" DIA 2 7/8" OD 8RD EUE TBG THD

7" – 17# – 35# & 65/8 " – 17# – 20# 7 5/8" – 20# – 39# MIN ID 2.366

NOTE : DIMENSIONS MARKED WITH * ARE FOR LONG CIRCULATING VALVE ASSEMBLY PART No. 696.5718 2179/55

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PACKERS: HALLIBURTON RTTS PACKER FIGURE 3

NOTE:

FIRST PART NO THD AND DIMENSION LISTED IS FOR 8 5/8 " SIZE; SECOND IS FOR 9 5/8 " SIZE; THIRD IS FOR 10 3/4 " SIZE AND FOURTH IS 13 3/8 " SIZE. WHERE ONLY ONE IS LISTED IT APPLIES FOR ALL SIZES CIRCULATING VALVE ASSEMBLY 696.601 696.6018*

9.8"

12.87" 18.87"*

6.60" 3.78" DIA 12.60"*TRAVEL 3.00" ID

4 1/2 " API FULL HOLE TOOL JOINT BOX 3 13/16 " – 10N – 3THD

5.75" DIA 5 1/32 " – 8N – 3THD

8.37" 4.90" DIA 7.10" 13.10"* 3.12" ID

3.31"

133.55" 134.13" 134.13" 138.58" 145.55"* 146.13"* 146.13"* 150.58"* OVERALL

17.37"

10.63" TRAVEL 4.33" ID

4.25"

4 29/32 " – 8N – 3THD 3 7/8 – 8N – 3THD SAFETY JOINT ASSEMBLY 696.5922 5 1/8 " – 4 L.H. STUB ACME THD. 6.00" DIA 5 1/32 " – 8N – 3THD PACKER BODY ASSEMBLY 696.597 696.607 696.617 696.637

7.8" 5 1/32 " – 8N – 3THD 15.32" 15.94" 15.94" 16.11"

10.32" 10.94" 10.94" 11.0"

2.44" ID

7.37" DIA 8.25" DIA 9.40" DIA 11.94" DIA

6.64" 9.67" 9.67" 11.86"

29.8" 29.8" 29.8" 31.30"

3.00" ID 3.00" ID 3.00" ID 5.65" ID

5.25" ID 5.75" ID 5.75" ID 8.70" ID

6.00" DIA 5 1/32 " – 8N – 3THD

3.56" ID 4.18" ID 4.18" ID 5.65" ID

7.62" – 8 5/8 " – 10 3/4 "

4 1/8 " – 10N – 3THD 4 1/2 " – 8N – 3THD 4 1/2 " – 8N – 3THD 6 3/4 " – 8N – 3THD 7.25" DIA 8.15" DIA 9.30" DIA 11.70" DIA 4 1/2 " DP THD – 8 5/8 " – 10 3/4 " 7 11/16 " – 8N – 3THD – 133/8 " 4 1/2 " 8RD – DP THD

RETRIEVABLE TEST TREAT SQUEEZE PACKER (RTTS) 8 5/8 " 9 5/8 " 10 3/4 " 13 3/8 " NOTE:

DIMENSIONS MARKED WITH * ARE FOR LONG CIRCULATING VALVE ASSEMBLY NO. 696.6018

2179/56

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PACKERS: HALLIBURTON RTTS PACKER FIGURE 4

696.60007 - SAFETY JOINT MANDREL

696.60009 - SAFETY JOINT NUT

70.34047 - "O" RING

70.36970 - PIPE PLUG NOTE : REMOVE PIPE PLUG AND INSTALL GREASE FITTING. FILL WITH GREASE THEN REPLACE PIPE PLUG.

696.59222 - SAFETY JOINT CASE 70.33936 - "O" RING - 4 REQUIRED

696.5923 - CONNECTOR

70.34045 - "O" RING

696.60035 - TENSION SLEEVE

SAFETY JOINT - RTTS 8 5/8" - 13 3/8" - 696.5922

2179/49

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PACKERS: HALLIBURTON RTTS PACKER FIGURE 5 * THESE PARTS ARE USED ON LONG CIRCULATING VALVE NO 696.6018

696.60001 - TOP ADAPTOR

70.33983 - "O" RING

70.33936 - "O" RING - 2 REQUIRED 70.36970 - PIPE PLUG

696.60003 - MANDREL - REGULAR 696.60182 - MANDREL - LONG * 696.6005 - J - SLOT SLEEVE - REGULAR 696.60183 - J - SLOT - LONG *

696.60005 - BODY

696.60002 - "O" RING - 3 REQUIRED

70.34045 - "O" RING

696.60041 - LOWER BODY - REGULAR 696.60181 - LOWER BODY - LONG *

70.33983 - "O" RING CIRCULATING VALVE - RTTS 8 5/8 " - 13 3/8" - 696.601 8 5/8 " - 13 3/8 " - LONG - 696.6018

2179/50


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PACKERS: BJ SERVICES MODEL 1223 PACKER

DESCRIPTION This proprietary packer (Figures 1, 2 and 3) may be used in the following situations: 1. Casing pressure tests. 2. Temporary well suspension, as a retrievable bridge plug (RBP) (in conjunction with the BJ hurricane plug). 3. Squeeze operations. (with cement, acid and Magnaplus). 4. Inflow testing. The Model 1223 Packer is a single-string, mechanically-set, retrievable, set-down packer with a triple element seal, automatic jay mechanism, hydraulic hold-down buttons and a full strength mandrel. When it is run with a BJ unloader valve, the packer may be used for pressure testing casing, squeeze cementing, formation fracturing and high-pressure acidising and subsequent well testing. The unloader valve adds a bypass above the packer during run-in and retrieval and provides a means to reverse the workstring above the packer before it is released. When it is used with the BJ hurricane plug, the assembly acts as an RBP, and can be used for temporary well suspension, to hang off during bad weather, allow removal of wellheads and BOPs etc.

2

TYPICAL SETTING AND RELEASING PROCEDURE When the packer has been run to setting depth, it is set by using workstring rotation and slack-off weight as follows: 1. Pick up the packer at least one foot at setting depth. 2. Rotate the workstring to the right, at least one turn at the packer (this releases the auto jay safety mechanism on the packer and the unloader valve when it is run) and simultaneously lower the workstring to set the slips, close the unloader valve and seat the packing elements against the casing wall. 3. Slack-off 6000 to 30,000 lbs (depending on packer size) at setting depth to complete the setting procedure. The packer is released by picking up the workstring. This is preceded by applying 100psi on the annulus to ensure that the hold-down buttons are fully retracted. After unseating the packer, it should be left in place for 5 minutes to allow the elements to shrink back to clearance diameter.

3

TO OPEN, CLOSE AND LOCK THE UNLOADER VALVE WHEN PACKER IS SET Rotate the workstring to the right and pick up to the free point. Apply pressure down the string and pick up until circulation to the annulus is established. Any overpull will indicate that the packer is being unset. To lock the unloader valve open, rotate the workstring to the left then reapply the original setdown weight. To close and lock the unloader valve closed, reverse this procedure.

4

HURRICANE PLUG OPERATION Before running in the hole the hurricane plug (Figure 4) should be split and the free operation of the valve checked by tapping it with the wooden shaft of a sledgehammer. On reassembly, the fishing neck section should only be hand torqued with a maximum 36in chain tong. To come off the hurricane plug, set the packer as normal, with the setting weight positioned below the packer and pick up the workstring to the free point. Rotate the workstring to the left, at least nine turns at the tool while picking up to maintain free point (this allows the spring loaded valve to close). When free of the assembly, it must be pressure tested to ensure that the valve has fully closed. A Hi-Vis pill should be circulated above the assembly, to protect it from debris and settlement.


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HURRICANE PLUG RETRIEVAL Before tagging the hurricane plug, care must be taken to ensure that well control equipment in the form of a kelly cock or similar, is fitted at the top of the workstring to control any gas which may have accumulated under the assembly. Upon engagement of the hurricane plug, any accumulations will be free to vent up the workstring. To retrieve the hurricane plug, it should be tagged gently while circulating. Upon tagging the plug the pumps should be turned off and the workstring rotated to the right, no more than 10 turns at the tool. Applying 100psi to the annulus will indicate that the assembly is fully engaged and sealed. The packer can then be unset as normal.

6

PRE RUN CHECKS When the packer has been made up in rotary the top and bottom packer subs have to be made up onto the packer main mandrel. To do this use the conventional rig tongs and with the backup on the bottom packer sub and make-up tong on the top packer sub, tighten both subs against each other to 8000 lbs at the tool. With the dragblock housing at waist level, rotate the dragblocks anticlockwise 1/4 turn and lift housing straight up to engage the cone into the casing slips to extrude the slips outward. Note:

As the MR 1223 Packer has no internal bypass, there is a need for an additional unloader valve to be run on top of this packer to reduce ramming and swabbing affect. However, it is not standard practice for us to use this unloader valve when running a hurricane plug to shallow depths.


SUBJECT:



Figure 1 BJ Services 7in 1223 Packer

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Figure 2 BJ Services 9 5/8in 1223 Packer

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Figure 3 BJ Services 13 3/8in 1223 Packer

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Figure 4 BJ Services Hurricane Plug

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DRILLING JARS

1.

SELECTION OF DRILLING JARS

1.1

The choice of drilling jars is to be restricted to the Dailey LI or Weir Houston Hydra Jar.

1.2

The Dailey jars should normally be run in tension but can be run in compression if it is necessary to place the jars near to the bit.

1.3

Dailey jars should not be run in kick-off assemblies. Serious consideration should be given to using hydraulic jars in deviated holes.

1.4

Weir Houston Hydra jars should be run in tension, although in exceptional cases they can be run in compression provided that only light weight is hung below the jars.

2.

RUNNING DRILLING JARS

2.1

Sufficient weight must be available above the jars. Consideration should be given to consulting the Jarpro programme for optimising placement of the jars.

2.2

Drilling jars should be uncocked and extended before running in the hole.

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HYDRIL RETRIEVABLE DROP-IN CHECK VALVE

1.

GENERAL

1.1

A drop-in check valve sub will be run at all times in the drill string below the conductor shoe. Whenever possible, this type of check valve is to be used in preference to an NRV-type inside BOP and may be used in conjunction with a float valve. The most commonly used type of check valve is the Hydril “Checkguard” which is rated to 10,000 psi working pressure. It provides positive closure against well pressure inside the drillpipe and opens for normal circulation of drilling fluid.

1.2

The Checkguard is composed of three components (see Figures 1 and 2): 1. 2. 3.

1.3

The landing sub. The check valve. The retrieving tool.

The landing sub is an integral member of the drill string, and is usually placed low down in the heavyweight drillpipe (it should not be placed at the crossover from heavy-weight drillpipe to drill collars). The ID of the landing sub for use with 4 1/2” IF connections and 6 1/2” OD tool joints is 2 5/8”. It is, therefore, necessary to remove the sub prior to the use of certain drillpipe wiper darts, such as liner wiper darts. The check valve is inserted into the drill string when required. The landing sub embodies an internal shoulder above the landing shoulder. After the check valve has landed, upward pressure closes the valve and lifts it slightly permitting a circular slip on the valve to positively stop against the upper shoulder and lock the valve body to the sub (Figure 1). Simultaneously, a rubber packer on the valve is energised to seal off all the fluid bypass.

2.

INSTALLATION PROCEDURE

2.1

Prior to running the landing sub, ensure that the drill string ID above the landing sub is at least 1/16” larger than the check valve OD of 2 5/8”. Prior to using the check valve, visually examine the packer element and replace if required.

2.2

The check valve can be installed in the string by pumping it down or by allowing it to free-fall.

2.3

When there is pressure on the drill string below a closed full-opening stab-in valve, it will be necessary to balance pressure against the stab-in valve after installing the check valve in the kelly and making it up to the string. Once the pressure is balanced the stab-in valve can be opened allowing the check valve to pass.

2.4

If the valve is to be pumped down, it should be installed in the drill string and circulation established at the normal drilling flowrate. Approximately 100m before the valve is due to land, reduce the flowrate to a minimum.

2.5

The only real test to prove that the check valve has landed and is locked in place is to bleed off pressure from the drillpipe and to observe that no flow occurs. If there was no pressure on the drill string prior to installation of the valve, it will be necessary to induce pressure to the drill string by pumping against the closed BOP.

3.

RETRIEVAL PROCEDURES

3.1

There are three methods for retrieving the drop-in check valve: 1) 2) 3)

Pulling the landing sub. Running the retrieval tool on wireline. Pumping down the retrieval tool on wireline.

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HYDRIL RETRIEVABLE DROP-IN CHECK VALVE

Wireline Retrieval For wireline retrieval it is essential that a suitable crossover is available to the type of wireline system in use. In addition, sinker bars with compatible threaded connections must be available. It is recommended to run as many sinker bars as possible to achieve successful retrieval.

3.3

If the valve is to be retrieved while the drill string is under pressure, a wireline stuffing box or lubricator system must be used.

3.4

The preferred method of wireline retrieval is with the logging unit as this offers the most control, sensitivity and depth correlation.

3.5

RIH with the wireline assembly to 3 joints above the landing sub. Adjust the descent rate to 1 - 2 m/sec until the tool is landed. Release the valve with a straight pull.

Note: a) No overpull should be required to release the valve. b) Unless there is pressure trapped below the check valve, there is no positive indication that the valve has been released from the landing sub. 3.6

Pumpdown Retrieval This method will be required if it is not possible to run the retrieval tool assembly under its own weight. The same retrieval assembly is run but a circulating head complete with stuffing box or lubricator is required to pump the assembly to the landing sub. Once the assembly is installed in the string, circulate at the normal flowrate. Three joints above the landing sub, reduce the flowrate such that the fluid velocity is 1 - 2 m/sec and observe for a pressure increase as the tool lands in the sub. Pressure surge the retrieval tool onto the valve to ensure that it has landed. Recover the assembly on wireline.

3.7

The check valve is disengaged from the retrieval tool by compressing the valve slips, while at the same time pulling the valve away from the retrieval tool.

4.

CHECK VALVE MAINTENANCE

4.1

Disassemble the check valve.

4.2

Wash and inspect each component of the valve for wear and replace as required.

4.3 Always replace the packer element after use. Re-assemble all parts dry no lubrication or preservative is required. 5.

LANDING SUB MAINTENANCE

5.1

Periodically check the landing sleeve for fluid erosion or scoring.

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HYDRIL RETRIEVABLE DROP-IN CHECK VALVE FIGURE 1

LANDING SUB

CHECK VALVE

CHECK VALVE LANDING SUB WITH CHECK VALVE INSTALLED

2179/178

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HYDRIL RETRIEVABLE DROP-IN CHECK VALVE FIGURE 2 CHECK VALVE RETRIEVING TOOL

2179 /179

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DRILL STEM CIRCULATING SUBS

APPLICATION It may be advantageous to have a large flow area circulating sub in the drill string for any of the following reasons: a)

If tools with restricted or convoluted flow paths are in the drill string. These tools may include: -

MWD tools. Core barrels. PDM/turbines. Bits dressed with small nozzles.

b)

Where lost circulation is a strong possibility and an unrestricted flow path for coarse LCM plugs is required.

c)

Where the bit nozzles are liable to plug.

d)

Where high weight mud is in use and restricted flow area tools such as those mentioned above could become choked with settled barite after a static period. This may occur, for example, during a well control situation.

e)

Where it may be necessary to spot a cement or barite plug.

f)

For stripping pipe into the hole when restricted flow area tools are in the string.

g)

Where it is a planned emergency procedure to cement in the bit or bottom hole BHA. The circulating sub could be used to circulate the annulus clean above the sub, prior to back-off.

h)

Where there is a possibility that mud properties could become poor due to high temperatures or chemical contamination. This may result in high viscosities and gel strengths, which can cause problems if restricted flow area tools are in use. In this situation, it would be desirable to have a large flow area bypass tool available near the bit to avoid a wet trip and swabbing.

i)

Where use of the “U”-tubing method may be necessary to free differentially stuck pipe.

2.

CONSIDERATIONS WHEN RUNNING THE CIRCULATING SUB

2.1

The tool should be situated as close to the bit as possible, but above any restricted flow path tools.

2.2

The tools are fairly robust (Figure 1) and generally require an operating surface pressure of 2000 - 3000 psi to shear the retaining pin, move the sleeve and expose the flow ports.

2.3

The pressure drop through the tool must be taken into consideration. It is unlikely that under normal drilling conditions this pressure would be sufficient to shear the retaining pin. However, continuous use of the tool could weaken the pin by fatigue. Therefore, tools in continuous use should have the shear pin replaced periodically.

2.4

Do not install a shear pin which requires a surface pressure to shear it out greater than the pump liner pressure rating.

2.5

The sub must be inserted in the drill string below the dart sub. If it becomes necessary to strip in hole, the circulating sub will have to be opened (with a 2 1/4” ball) prior to dropping the Hydril dart (of 2 5/8” OD). This will leave an uncirculated sump of hydrocarbons below the sub which will have to be considered when killing the well. If heavy weight mud is in use, it may be possible that the barite settles out in the uncirculated sump, causing stuck pipe problems.

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DRILL STEM CIRCULATING SUBS

2.6

Ensure that there is no requirement to run wireline tools, wiper darts, etc. which require greater than 2 1/16” ID for clear passage.

2.7

The circulating sub is to be considered as a reserve option and should not be opened without careful consideration.

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DRILL STEM CIRCULATING SUBS FIGURE 1

A TYPICAL CIRCULATING SUB

DRILLING FLUID FLOW BEFORE PIN IS SHEARED

DRILLING FLUID FLOW AFTER PIN IS SHEARED

HOUSING

SLEEVE

DRILLING FLUID FLOW

"O" RING SHEAR PIN SPACER THREAD SEALANT PIPE PLUG

DRILLING FLUID FLOW 2179 /180

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BYPASS VALVES

1.

GENERAL

1.1

Bypass valves (tools or subs) are run in the string to reduce or eliminate backflow up the string when running tools of limited annular clearance. In the case of OBM, this backflow can lead to serious pollution problems.

1.2

Whenever possible, bypass valves will be run when there is a possibility of backflow occurring in the drill string.

1.3

Running the following equipment may require the use of a bypass valve: -

Scab liners. PBR’s. Liner overlap/retrievable packers. Cement retainers/bridge plugs. Casing patches. Core barrels. Washover strings and other fishing tools.

2.

TYPES OF BYPASS TOOLS

2.1

The main types of available bypass tools are: i)

“J” slot tools: e.g.

ii)

Halliburton RTTS Circulating/Bypass Valve (refer to Section 5235/GEN).

Pull-push tools: e.g.

Baker (Brown) Circulating/Bypass Valve. Halliburton Ful-Flo Hydraulic Circulating/Bypass Valve. Dowell Positest Bypass Valve.

iii) Flow actuation tools: e.g. 2.2

Mud Motor Bypass Valves (Dyna-Drill, Drilex, Navi-Drill, etc.).

Where the use of bypass valves is not applicable, other methods of controlling flow up the drillpipe must be sought. One possible alternative would be to install a closed valve on the top of the stand of drillpipe. Once the stand is run in, the valve is opened and the pressure built up is bled off with the returned fluid being routed to the tanks. This method has the disadvantage that pressure is built up in the hole and tripping time is increased. The advantage of the method is that an additional tool need not be run in the string.

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DRILL STRING LIFTING AND HANDLING EQUIPMENT

BP OWNED ELEVATORS Ensure that all elevators: a)

Have acceptable technical material specifications.

b)

Have full material traceability on all five main load bearing components (body, door, latch, latch pin and hinge pin).

c)

Are fully inspected as per BP’s Internal Inspection Procedures.

d)

Have current load test certificates as witnessed by a competent third party.

e)

Will be repaired either by a repair facility approved by the manufacturer, or a repair facility approved by BP to a procedure approved by the manufacturer.

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HEAVE COMPENSATION SYSTEMS

1.

RISER TENSIONERS

1.1

Riser tensioners provide positive axial tension to the Marine Riser. They typically have the capacity to supply 80,000 lb tension (each unit) with up to 50 ft compensation. The tensioners are combined in pairs with most rigs having either 8 or 10 units (giving a total tension of 640,000 lb or 800,000 lb). They are designed to supply the full rating on a continuous basis.

1.2

The tensioner system comprises (Figure 1): Tensioner Unit Power Air Pressure Vessels (APV) Standby APV’s Control Panel Air Compressor The tensioner line is reeved over multiple sheaves at the fixed and moveable ends of the tensioner, then over an idler sheave and connected to the support ring on the top of the riser pipe. The large volume APV’s provide a “constant” air pressure which acts on an oil filled accumulator on each tensioner unit. Oil pressure causes the tensioner piston rod to move in or out depending on whether the line tension is instantaneously higher or lower than the value equivalent to the system pressure. This constant adjustment of the line length maintains a tension in the line to ± 3% of the set tension.

1.3

The technique of utilising an air/oil interface in the accumulator ensures full lubrication on the high pressure side of the piston and prevents corrosion which would result from contact with hp air.

1.4

The low pressure end of the operating cylinder is also oil filled. As the rod extends oil flows through a speed control valve into a low pressure air/oil reservoir. When the rod retracts the oil flows in the opposite direction. The device has the effect of lubricating the cylinder and damping the rod motion. Should the tensioner line break, the rod would extend to its full stroke, but at a controlled rate.

1.5

The tensioners are typically installed with the rod end up and can be mounted on a twin mounting pad carrying two units.

1.6

The wire rope must be replaced on a periodic basis to prevent breakage. To determine replacement time, the number of ton cycles is calculated by estimating an average number of heave cycles per day and multiplying that by the line load. The slip and cut procedure would be as follows: a)

Stand down a riser tensioner and its opposite number to give an equally distributed radial loading on the telescopic joint support ring.

b)

Recover wires and shackles from the support ring of the telescopic joint. Note any excess wear on the support ring pad eyes.

c)

Release the wireline clamp on the side of the riser tensioner and pull through the required length of wire to be slipped.

d)

Refasten the wireline clamp on the riser tensioner.

e)

Remove the wireline clamps from the tensioner end of the wire.

f)

Cut off the required length of line, preferably with a cutting torch to a fused end.

g)

Refasten the end of the wire to the wireline clamp. N.B. Bulldog clips have a right and wrong way of fastening; if in doubt, ask.

h)

Connect the wires to the riser tensioner support ring.

i)

Actuate the riser tensioner.

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FIGURE 1

RISER TENSIONER (SHAFFER)

AIR PRESSURE

LOW PRESSURE SEAL 2

SAFETY SPEED CONTROL VALVE

2

ACCUMULATOR

CONTROL PANEL

AIR-OIL RESERVOIR 20-40 psi

4 3

4

AIR SOURCE

1

HIGH PRESSURE SEAL CYLINDER

VENT

VENT

2

1. 2. 3. 4.

LOW PRESSURE AIR HI PRESSURE AIR LOW PRESSURE OIL HI PRESSURE OIL

2179 / 45

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2.

GUIDELINE TENSIONERS

2.1

Guideline tensioners provide positive tension in the guidelines connecting the rig to the drilling guidebase. There is one tensioner unit for each of the 4 guidelines, each unit typically having a capacity of 16,000 lb with 40 ft of compensation.

2.2

The tensioner system comprises (Figure 2): Tensioner Units Power APV’s Control Panel High Pressure Air Source The operation of the system is similar to the riser tensioner operation except that the power fluid is air only. Guideline storage and the dead end of the cable is accommodated on an air tugger located on the cellar deck. The capacity of the tugger must be maximum water depth + 200 ft for hook-up, air gap and line replacement. The brake capacity of the tugger must exceed the capacity of the tensioner (16,000 lb) but the inhaul capacity is typically about 4,000 lb. In addition to the 4 guideline tensioners, there are usually another two to give compensation on the BOP control pod line and the underwater television line.

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HEAVE COMPENSATION SYSTEMS FIGURE 2

GUIDELINE TENSIONER (SHAFFER)

AIR PRESSURE VESSEL

LOW PRESSURE SEAL

2

SAFETY SPEED CONTROL VALVE

AIR-OIL RESERVOIR 20-40 psi

CONTROL PANEL

3

TENSIONER ACTIVATOR HIGH PRESSURE AIR SOURCE

2

1

HIGH PRESSURE PISTON SEAL CYLINDER

VENT

AIR VENT

2

1. 2. 3.

LOW PRESSURE AIR (20-40 psi) (200-1800 psi) HI PRESSURE AIR LOW PRESSURE OIL (20-40 psi)

2179 / 46

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3.

DRILL STRING COMPENSATOR

3.1

The drill string compensator (DSC) is mounted between the travelling block and the hook and is designed to nullify the effect of vessel heave on hook load. Typically compensators used on rigs in the North Sea have a capacity of 400,000 to 600,000 lb (compensating) with 18 or 20 ft stroke. The Shaffer system described below achieves 400,000 lb compensation rating at an operating pressure of 2260 psi.

3.2

The system comprises (Figure 3): Motion Compensator Unit Hydraulic/Pneumatic Operating System Control Panel High Pressure Air Source Some systems are fitted with a hydraulic latch which locks the compensator at whatever stroke and hook load setting it is at a few seconds after the “lock” button is pressed. The Shaffer system utilises hp air as the power fluid. This is supplied to the compensator unit from a bank of APV’s through a standpipe manifold and a hose bundle looped from the manifold to the compensator. The low pressure ends of the operating cylinders are oil filled and are connected to a low pressure air/oil reservoir through a speed limiting valve. The oil lubricates the cylinder and the valve provides motion damping especially in the event that the hook load is suddenly lost. In this case the valve prevents the very rapid extension of the rod which would otherwise occur. The system shown incorporates a chain linkage between the upper yoke of the compensator attached to the travelling block and the lower yoke attached to the hook. This allows an 18 ft movement for a 9 ft stroke, reduces the loading on the unit and the required derrick height to accommodate the unit. The total load capacity of the chain is 1,500,000 lbs with the replacement time being determined by a simple length measurement indicating bearing wear. (Manufacturers state about 6 years chain life.) The lock bar feature on the compensator allows the lower yoke to be locked to the upper yoke, thus effectively locking the hook to the travelling block. The mechanism is operated by hydraulic pressure. The control console located near the driller’s station allows the driller to monitor: Compensator Stroke Position Compensator Hook Load (Pressure) Lock Bar Position Standby APV Pressure and to control: Compensator Load/Pressure Lock Bar Operation Air/Oil Reservoir Pressure The stroke position indicator displays the compensator position relative to its upper and lower stroke limits.

3.3

Operation of the Compensator 1.

The drill string compensator is used to control the weight on bit while drilling and to nullify the effect of the rig heave when performing such operations as landing/pulling the BOP, landing casing, logging, landing off the drill string, etc.

2.

The length of the kelly must be greater when a compensator is in use to accommodate the effective stroke of the unit. For instance, it is typical to use a 45 ft kelly on a rig using range 2 drill pipe (up

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to 30 ft) and a compensator with an effective stroke of 15 ft (18 ft total stroke). 3.

The maximum derrick height required occurs when picking up the drill string from the slips after adding a stand of drill pipe and with the compensator fully stroked open. If sufficient clearance is not available, it will be necessary to lock the compensator.

4.

The level of compensation delivered by the unit (the tension setting) will depend on the air pressure in the system. In a drilling mode weight on bit is equal to the weight of the drill string minus the tension setting. While drilling ahead the driller incrementally lowers the travelling block to account for drill off and to maintain the compensator cylinder within its stroke capacity. In this way the compensator automatically maintains the selected bit weight. Example:

3.4

-

Total MD Weight Block and DSC Main Frame Weight

250,000 lbs 55,000 lbs

= -

Drill String Weight Required WOB

195,000 20,000

=

DSC Setting

175,000 lbs

The following operating procedures illustrate suggested methods for utilising the compensator. Other methods may be equally valid. 1.

Prior to reaching bottom or reaming depth: Install the kelly (lock bar closed) and set the drill pipe in the slips. Energise the compensator cylinders to the required APV pressure. Both rods will extend to full stroke. Unlock the lock bar. Lift drill string out of the slips. The DSC will be fully extended. Lower block until DSC is at mid position. The DSC is now compensating for the present WOB.

2.

To add a single: Pull kelly out of hole and set slips. DSC will be fully extended. Lower block to completely retract the DSC and lock the lock bar. Break pipe and install single. Pick up out of slips and lower string, resetting slips below kelly. Unlock the lock bar and raise block to fully extend the DSC. Pull slips and RIH until DSC shows mid position and commence drilling.

Note: On systems fitted with a hydraulic latch, the DSC can be locked when picking off bottom for a connection. The connection is made and when the hook load returns to the same value as when the DSC was locked, it can be unlocked to drill ahead with compensation. 3.

Running casing: Run casing with running tool installed to 5m above land off point and set slips. Note total MD weight and subtract 20,000 lbs (landing weight) + 55,000 lbs (block weight) and set DSC for this level. Raise block to fully extend DSC and lift casing off slips. Lower string to landing point, allowing DSC to reach mid stroke position. Set brake. Calculate landing string and running tool weight and add to this 30,000 lbs (weight of lower yoke, hook, bails and elevator). Set this weight on the DSC and remove the running string.

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Running BOP: Run riser/stack and add slip joint. Note MD weight. Run stack to 5m above wellhead (slip joint closed). Support riser in hang-off tool. Subtract 55,000 lbs (block and DSC frame) + 20,000 lbs (landing weight) from MD reading and set this value on DSC. Open lock dogs on slip joint. Open lock bar on DSC. Raise block to fully extend slip joint and fully extend the DSC. Release the dogs on the hang-off tool. Lower block to land BOP stack and continue to lower till DSC at mid stroke position. Set brake and allow DSC to compensate. Latch the BOP connector and attach riser tensioners. Close DSC and lock bar prior to commencing pull test on the wellhead. (Note the riser tensioners can be activated prior to landing the stack. If the total load set on all tensioners is 120,000 lbs say, then the procedure above is followed but the DSC setting will be 120,000 lbs less in this case.)

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HEAVE COMPENSATION SYSTEMS FIGURE 3 DRILL STRING COMPENSATOR ( SHAFFER )

TRAVELLING BLOCK

CHAIN

SPEED LIMITING VALVE

,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,,

,,,, ,, ,, ,,,, ,, ,, ,,,, ,, ,, AIR / OIL RESERVOIR ,,,, ,, ,, ,,,, ,, ,, ,,,, ,, ,, 3 ,,,, ,, ,, ,,,, ,, ,, ,,,, ,, ,, ,,,, ,, ,,,, ,, ,,,, ,, ,,,, ,, 2 ,,,, ,,,,

LOW PRESSURE OPERATION ROD SEAL

,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,, ,,,,,,,

2 ROD END HYDRAULIC

AIR SAFETY VALVES 2 1 2 3

HIGH PRESSURE PISTON SEAL CUSHION BLIND END HYDRAULIC CUSHION

HIGH PRESSURE AIR 200-2400psi

,,,, OIL ,,,, ,,,,

LOCK BAR SLOTS

,,,, LOW PRESSURE AIR 20-40psi ,,,,

1 HOOK

STAND PIPES (2)

AIR SAFETY VALVES

VALVE MANIFOLD

(1)

POWER AIR PRESSURE VESSELS

AIR HOSES (4)

CONTROL CONSOLE

AIR COMPRESSORS

STANDBY AIR PRESSURE VESSELS HIGH PRESSURE AIR FOR DRILL STRING COMPENSATOR AND RUCKER TENSIONER SYSTEM

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COMPENSATION WHILE LOGGING The DSC is used to allow compensation to the logging line using the set-up shown in Figure 4. A special 1 1/8” galvanised working wire with one end secured to the rig structure and the other to the riser support ring is passed through a sheave supported by the DSC. A second sheave supported from this carries the logging cable. The working wire incorporates a weak point of 18,000 lbs rating and a safety tie line. The shackle point welded to the rig structure is special steel and normally supplied by the logging contractor. In operation the DSC is set to compensate for 10,000 lbs hook load and the block positioned to put the compensator at mid stroke.

DSC

Working Wire Logging Cable Weak Point Rig Floor Tie Line

Riser FIGURE 4

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5.

SPECIAL CONSIDERATIONS

5.1

Vetco Drill String Motion Compensator When operating the Vetco compensator system at the precharge and minimum operating pressure of 300 psi, it has been known for the compensator to temporarily lock close. Therefore, when operating this equipment with a minimal string weight, the minimum operating pressure must be 500 psi. In order to achieve this, the string weight to be used must be designed such that the primary hydraulic system operating pressure is not less than 500 psi at any time.



Index Prefixes 0000


1000

Drilling

2000

Casing and Tubing

3000

Cementing

4000

Drilling Fluids

5000


6000


7000

Well Evaluation

8000






Section

Description

6000

STUCK PIPE AND FISHING

6000/GEN

Stuck Pipe Prevention and Procedures

6005/GEN

Calculation of Optimum Fishing Time

6010/GEN

Freeing Differentially Stuck Pipe Using the “U”-Tube Method

6020/GEN

Freeing Stuck Pipe Whilst Drilling Riserless and From Fixed Installations

6050/GEN

Jar Placement and Jarring Practices

6100/GEN

Effective Pull on Stuck Pipe

6150/GEN

Free Point Determination and Back-Off Procedures

6200/GEN

Fishing - Procedures and Tools

6250/GEN

Stuck Logging Tools

6410/GEN

Casing Milling

6420/GEN

Section Milling

6430/GEN

Casing Milling and Underreaming for Open Hole Gravel Pack

6500/GEN

Bit Nozzle Removal


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STUCK PIPE PREVENTION AND PROCEDURES

1.

CAUSES OF STUCK PIPE

1.1

Introduction There are numerous causes of stuck pipe; some occur regularly, some may be peculiar to a particular area and some may be unique. A string may become stuck because of any one or combination of these, although historically in BP’s operation stuck pipe due to packing off and differential sticking mechanisms has accounted for approximately 72% of incidences. Industry convention categorises the causes as either differential or mechanical sticking.

1.2

Differential Sticking During most drilling operations, the pressure exerted by the mud column is greater than the pressure of the formation fluids. In permeable formations, mud filtrate will flow from the well into the rock, building up a filter cake. A pressure differential will exist across the filter cake, which is equal to the difference in the pressure of the mud column and the formation. When the drill string touches the filter cake, any part of the pipe which becomes embedded in the cake will be subject to a lower pressure than the part which remains wholly in the well. If the pressure difference is high enough and acts over a sufficiently large area, the pipe may become stuck. See Figure 1. The force required to pull differentially stuck pipe free depends on:

1.3

a)

The difference in pressure between the borehole and the formation. Any overbalance adds to side forces which may exist due to the deviation of the hole.

b)

The surface area of pipe embedded in the wall cake. The thicker the cake or the larger the pipe diameter, the greater this area is likely to be.

c)

The coefficient of friction between the pipe and the wall cake is a very significant factor, being directly proportional to the sticking force. It tends to increase with time, making it harder to pull the pipe free. This is demonstrated clearly in Figure 2, which shows more than a tenfold increase in the coefficient of friction in three hours. This graph is for a bentonite filter cake and drill pipe. Different filter cakes will give different profiles.

Mechanical Sticking Mechanical sticking results from one, or a combination, of the following: a) b) c) d) e) f)

1.3.1

Inadequate hole cleaning. Sloughing and swelling formations. Key seating. Running into undergauge hole. Drilling plastic formations. Large boulders falling into the hole.

Inadequate Hole Cleaning If cuttings are not removed from the well, they will settle around the drill string, usually the BHA, causing the hole to pack off and the pipe to become stuck. The problem is exacerbated in overgauge sections where the annular velocities are reduced. Cuttings will build up and eventually slump into the hole. High angle wells are more difficult to clean than vertical ones, because of the tendency of the drilled solids to fall to the low side of the hole. In a vertical well, provided the circulation rate is higher than the slip velocity of the cuttings, then the hole will be cleaned. In highly deviated wells, the cuttings have only a short vertical distance to fall, before they will lie on the low side of the hole. Beds of cuttings will be formed which are not easily removed. Problems can be caused when tripping out of the hole, as the

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STUCK PIPE PREVENTION AND PROCEDURES FIGURE 1 DIFFERENTIAL STICKING

MUD CAKE

FORMATION PRESSURE PF MUD PRESURE PM

BOREHOLE WALL PIPE

CONTACT ARC R

FRICTION COEFFICIENT CF

CONTACT AREA Ac PRESSURE DIFFERENTIAL P STICKING FORCE FORCE TO PULL PIPE FREE

= = = =

R x STUCK LENGTH PM - PF P x AC P x AC x C F

2179/186

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STUCK PIPE PREVENTION AND PROCEDURES FIGURE 2

INCREASE IN MUD CAKE FRICTION CO-EFFICIENT WITH TIME

5 FRICTION CO-EFFICIENT (No. UNITS)

SUBJECT:

Section

4

3 CURVE FOR BENTONITE MUD 2

1

0 0

40

80

120

160

200

240

280

TIME (MINUTES)

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BHA will be pulled into the cuttings beds. The cuttings will be dragged up in front of the top collar or stabiliser, until the hole packs off or the pipe is pulled tightly into a plug of cuttings. 1.3.2

Formation Instability Some formations can plastically extrude into the hole and close around the pipe, while others can slough and cause a hole to pack off. For example, coal is prone to sloughing, salt will extrude and shales can do either. Uncemented sands and gravels can slough into the hole, giving large overgauge sections and possible hole cleaning problems. Heavily fractured limestones can result in a succession of boulders falling into the well, jamming around the BHA and causing the pipe to stick. Shales The stability of shales is governed by several factors, including the weight of overburden, in-situ stresses, angle of bedding planes, moisture content and their chemical composition. Shales can be split into two categories: a)

Brittle or Sloughing Shales These shales fail by breaking into pieces and sloughing into the hole. Sloughing can be recognised by large amounts of shale on the shakers at “bottoms up”, drag on trips and high levels of fill.

b)

Swelling Shales Some shales swell as the result of a chemical reaction with water known as hydration. The clay platelets, which make up shales, are pushed apart by the water and the formation expands. The amount of swelling varies from the highly reactive “gumbos” to shales which hydrate very slowly. However, any swelling shale is a potential cause of stuck pipe. Gumbos will swell very rapidly and very dramatically. Given sufficient free water the clay platelets will separate completely, expanding to several times their original volume. The hole can be cleaned at controlled rates of drilling, but it may need to be redrilled after each joint, as the clays continue to swell.

Hole Orientation Shales are weaker along the formation bedding planes than across them. Because of this, holes drilled at different inclinations and directions through the same formation may vary greatly in stability. Increasing the mud weight will help to stabilise a formation, while frequent short trips and careful drilling practices can help to minimise stuck pipe risks. 1.3.3

Key Seating A key seat is caused by the drill string rubbing against the formation. The body and tool joints of drillpipe wear a groove in the rock about the same diameter as the tool joints. The wear is confined to a narrow groove, because the high tension in the drill string prevents sideways movement. During a trip out of the hole, the BHA may be pulled into one of these grooves, which may be too small for it to pass through. See Figure 3. Key seats are often associated with doglegs, as the drill string will be forced into contact with the formation. The more severe the dogleg, the greater the side load will be and so the faster a key seat will develop. Other than doglegs, ledges are features which provide points of continuous contact. Further variations include key seats at casing shoes, where the groove is made in metal instead of rock. Development of key seats is dependent upon the number of rotating hours.

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STUCK PIPE PREVENTION AND PROCEDURES FIGURE 3 FORMATION OF KEY SEAT

SECTION A-A

A

DRILL COLLAR

A

1. ILLUSTRATING KEY-SEATING EFFECT ON CROOKED HOLE

2. POSITION OF PIPE AFTER KEY SEATING

3. DRILL COLLAR STUCK IN KEY SEAT

2179 / 188

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Undergauge Hole and Assembly Changes Abrasive hole sections will tend to not only dull bits, but also to reduce their gauge and that of the stabilisers. Attempting to maximise the length of a bit run in an abrasive formation may prove to be a false economy, as undergauge hole will inevitably lead to reaming operations. Reaming a long section will usually wear out a bit very quickly. A driller, tripping in at high speed, can jam a full gauge assembly into an undergauge hole and become stuck. Greater care is all that is needed to prevent this. A flexible assembly can “snake” around doglegs which present an obstruction to a stiff assembly. Formation drilled with a limber BHA may appear to be clean when pulling out, but when running a stiffer BHA, the newly drilled hole will act as if it were undergauge. Again there will be a risk of sticking the pipe.

1.3.5

Drilling Plastic Salts The plastic nature of salt formations may result in stuck pipe. When drilling into salt, stresses will be relieved and the formation will extrude into the borehole. The encroachment can often be measured in fractions of an inch, but this may be sufficient to cause a bit or stabiliser to become stuck. The magnitude of the stresses and hence the rate of movement will vary from region to region but is generally greater for formations below 2000 metres (6500 feet). Abnormal pressures and flowing salts may be experienced anywhere with unequal relieved stresses, but most commonly at the top of a formation or on the flanks of salt domes.

2.

PREVENTION OF STUCK PIPE

2.1

Introduction There are very few cases of stuck pipe which are impossible to prevent. Many incidents could be avoided by more careful planning or greater care at the rig site. During the planning stage, it is essential that a study is made of offset well data, to look for potential stuck pipe problems. The Drilling Programme should contain a stuck pipe section, where troublesome formations, past problems and any recommended procedures should be listed. For example, it may be possible to decide at what intervals wiper trips should be made, by looking at their effect on hole conditions on previous wells. This information must be discussed at pre-spud meetings in town and on the rig site, if it is to make the necessary impact on the operation. Among the many people involved in the drilling operation, the Driller has a key role in preventing stuck pipe. Thorough planning, good drilling practices and an effective mud system will ensure that the hole is in the best possible condition. However, once a problem exists, the only person who can prevent it resulting in stuck pipe is the Driller. At the instant that the formation grabs the pipe or the hole packs off, it is the Driller’s reaction which is all important. The BP Representative must be sure that every Driller is aware of any special problems and what his immediate actions should be. The greater the Driller’s understanding of the problems, the greater the chance that he keeps the pipe free. The decision trees illustrated in Figures 4 - 12 illustrate the process required to identify the nature of a tight hole situation encountered when performing a particular operation.

2.2

General

2.2.1

Planning Stage a)

Careful attention should be paid to the likelihood of stuck pipe and a special section of the Drilling Programme should be dedicated to it. This would include the identification of the potential troublesome formations and any special procedures which should be adopted through these zones, such as frequency of wiper trips.

SUBJECT:

ROTARY DRILLING

CONNECTIONS (& SURVEYS)

TRIPPING IN

TRIPPING OUT

REAMING IN

REAMING OUT

CIRCULATING

RUNNING CASING

FIG. 5

FIG. 6

FIG. 7

FIG. 8

FIG. 9

FIG. 0

FIG. 1

FIG. 2

BP EXPLORATION

OPERATION

DRILLING MANUAL


SELECTION OF IDENTIFICATION DECISION TREE BASED ON OPERATION

Page

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2 (1/91)

6000/GEN

FIGURE 4

2179 /189

Y

STABILIZERS HANGING UP ON FORMATION LEDGES

BIT FAILURE STRING COMPONENT FAILURE

N

N

Y

INADEQUATE HOLE CLEANING

FRACTURED / FAULTED FORMATIONS

Y

Y

IS CIRCULATION RESTRICTED ?

IT IS POSSIBLE THAT A FAULT HAS BEEN DRILLED ?

N

Y

Y

NEWLY DRILLED GEOPRESSURED FORMS UNCONSOLIDATED FORMS FRACTURED / FAULTED FORMS FAST MOVING MOBILE FORM

N

HAVE PROBLEM FORMATIONS ALREADY BEEN EXPOSED ?

INCREASE IN TORQUE RELATED TO FORMATION CHANGE

SLOW MOVING MOBILE FORMATIONS REACTIVE FORMATIONS

N

ARE DRAGS REDUCED WHEN PUMPING ?

IS THERE A FORMATION CHANGE ?

IF TRI-CONE BIT BEARINGS WORN

CEMENT BLOCKS JUNK CASING KEYSEAT

Y

N

DRILLING MANUAL

N

UNDERGAUGE HOLE CAUSING STABILIZERS TO HANG UP ?

HAVE FORMATIONS OF VARYING HARDNESS BEEN DRILLED ?

WELLBORE GEOMETRY

Y

CAN DRAG BE RELATED TO DOG - LEGS ?

Y

Y

N

N

HAVE ABRASIVE FORMATIONS BEEN DRILLED

N

ARE HOLE DRAGS EXCESSIVE ?

ARE BIT HOURS EXCESSIVE ?

INCREASED TORQUE

SUBJECT:

ROTARY DRILLING


Rev. : 2 (1/91)

Page : 8 of 29


2179 /190

SUBJECT:

ARE KNOWN PROBLEM FORMATIONS EXPOSED ?


Y

ARE PERMEABLE FORMATIONS EXPOSED ?

N

2179 /191

REACTIVE FORMATIONS FRACTURED / FAULTED FORMS MOBILE FORMATIONS UNCONSOLIDATED FORMS GEOPRESSURED FORMATIONS

Y

JUNK CEMENT BLOCKS STABILISERS HANGING UP ON LEDGES

N

DIFFERENTIAL STICKING

FIGURE 6


N

6000/GEN

Y

:

JUNK CEMENT BLOCKS STRING COMPONENT FAILURE STABLISERS HANGING UP ON LEDGES

Section

CAN DRILLSTRING BE MOVED ?

2 (1/91)

IS DRAG REDUCED WHEN PUMPING ?

:

REACTIVE FORMATIONS FRACTURED / FAULTED FORMS MOBILE FORMATIONS UNCONSOLIDATED FORMS GEOPRESSURED FORMATIONS

Rev.

N

9 of 29

Y

:

N

Page

Y

BP EXPLORATION

DRAG TREND INCREASING WHEN MOVING STRING FROM STATIC

DRILLING MANUAL


MOVING PIPE FROM STATIC AFTER MAKING / BREAKING CONNECTIONS DURING DRILLING, TRIPPING AND REAMING OR AFTER SURVEY

REACTIVE FORMATION MOBILE FORMATION

N


WELLBORE GEOMETRY FORMATION LEDGES

N

Y UNDERGAUGE HOLE

WAS PREVIOUS BIT UNDERGAUGE ?

IS DRAG REDUCED WHEN PUMPING ?

Y

N


INADEQUATE HOLE CLEANING (CUTTING BEDS)

IS INCREASE SMOOTH OR ERRATIC ?

Y

Y

N

IS THERE EXCESSIVE UPWARD DRAG

SMOOTH

INCREASE IN DOWNWARD RESISTANCE

N Y FRACTURED / FAULTED FORMATIONS

N CEMENT BLOCKS JUNK STRING COMPONENT FAILURE

FORMATION LEDGES

WELLBORE GEOMETRY

DRILLING MANUAL

Y

HAS THERE BEEN A BHA CHANGE ON THIS TRIP ?

CAN RESISTENCE & DRAG BE RELATED TO FORMATIONS ?

UNDERGAUGE HOLE

Y

Y

REACTIVE FORMATIONS MOBILE FORMATIONS FRACTURED / FAULTED FORMS UNCONSOLIDATED FORMS

FORMATION LEDGES WELLBORE GEOMETRY CEMENT BLOCKS JUNK

ARE DOG-LEGS EXCESSIVE ?

N

N

Y


Y

N

HOLE BRIDGED CAN THIS BE RELATED TO PROBLEM FORMATIONS ?

N

IS THERE EXCESSIVE UPWARD DRAG

ERRATIC

SUBJECT:

TRIPPING IN


Rev. : 2 (1/91)

Page : 10 of 29


2179 /192

WELLBORE GEOMETRY FRACTURED / FAULTED FORM

N

Y



N

Y

Y REACTIVE FORMATIONS (BIT / STABILISER BALLING) MOBILE FORMATIONS UNCONSOLIDATED FORMS


N

Y

FORMATION LEDGES WELLBORE GEOMETRY

N

Y

Y

JUNK CEMENT BLOCKS

N


N

N

FORMATION LEDGES WELLBORE GEOMETRY

Y

CEMENT BLOCKS JUNK

Y

KEY SEATING

DOES ROTATING STRING ALLOW OBSTRUCTION TO BE PASSED ?

N

N

IS DOWNWARD MOTION POSSIBLE ?

ARE KNOWN PROBLEM FORMATIONS EXPOSED IN NEW HOLE SECTION ?

UNCONSOLIDATED FORMATIONS FRACTURED / FAULTED FORMATIONS

Y

IS DOWNWARD MOTION POSSIBLE ?

N

N

FRACTURED / FAULTED FORMATIONS

KEY SEATING

Y

CAN BHA BE ROTATED FREE ?


N


Y

ERRATIC

IS OVERPULL IN NEW HOLE SECTION ?

ARE KNOWN PROBLEM FORMATIONS EXPOSED IN HOLE SECTION DRILLED BY PREVIOUS BITS ?


N

ARE KNOWN PROBLEM FORMATIONS EXPOSED IN HOLE SECTION DRILLED BY PREVIOUS BITS ?


N

IS OVERPULL SMOOTH OR ERRATIC ?

DRILLING MANUAL


Y



REACTIVE FORMATIONS (BIT / STABILISER BALLING) MOBILE FORMATIONS UNCONSOLIDATED FORMS

Y

N

Y

Y

ARE KNOWN PROBLEM FORMATIONS EXPOSED IN NEW HOLE SECTION ?

IS OVERPULL IN NEW HOLE SECTION ?

SMOOTH

SUBJECT:

INCREASED DRAG OR OVERPULL

TRIPPING OUT


Rev. : 2 (1/91)

Page : 11 of 29


2179 /193

N

MOBILE FORMATIONS REACTIVE FORMATIONS UNCONSOLIDATED FORMATIONS



DO DRAGS INCREASE WHEN NOT PUMPING ?

UNDERGAUGE HOLE

Y

N

WELLBORE GEOMETRY (SIDETRACKING HOLE ?)


N

Y

N

N

INADEQUATE HOLE CLEANING (CUTTINGS BED)



Y

ARE DRAGS INCREASE WHEN NOT PUMPING ?

Y

N

Y

UNDERGAUGE HOLE



ERRATIC

ARE UP DRAGS EXCESSIVE ?


WELLBORE GEOMETRY FORMATION LEDGES JUNK CEMENT BLOCKS BIT FAILURE

N

DRILLING MANUAL

Y

N

Y

ARE HOLE DRAGS EXCESSIVE ?

Y


SMOOTH

INCREASED TORQUE INCREASED REAMING WEIGHT REQUIRED

SUBJECT:

REAMING IN


Rev. : 2 (1/91)

Page : 12 of 29


2179 /194

SUBJECT:

REAMING OUT

N

IS INCREASE IN TORQUE SMOOTH OR ERRATIC ?

ERRATIC

N

Y

N

IS DOWNWARD MOTION RESTRICTED ?

ARE DRAGS REDUCED WHEN PUMPING ?

JUNK CEMENT BLOCKS STRING COMPONENT FAILURE

Y

Y

Rev.

Section

:

:

2 (1/91)

6000/GEN

2179 /195

13 of 29



:

MOBILE FORMATIONS REACTIVE FORMATIONS

Y

FIGURE 10

WELL GEOMETRY FORMATION LEDGES STRING COMPONENT FAILURE

N


Page

KEY SEATING

SMOOTH

BP EXPLORATION


DRILLING MANUAL


INCREASED TORQUE AND DRAG

SUBJECT:


SMOOTH

ERRATIC



Y

N

DO DRAGS INCREASE WHEN NOT PUMPING ?

MOBILE FORMATIONS

CEMENT BLOCKS JUNK

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FIGURE 11

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MOBILE FORMATIONS REACTIVE FORMATIONS GEOPRESSURED FORMATIONS

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N

:



N

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Y

Y

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INCREASED DRAG & RESISTANCE

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CIRCULATING

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STUCK PIPE PREVENTION AND PROCEDURES FIGURE 12 RUNNING CASING

INCREASE IN DOWNWARD RESISTANCE WHILE RUNNING CASING OR AFTER CONNECTION

CAN PIPE BE WORKED UPWARDS ?

Y

N



Y

N

Y

ARE DOG LEGS EXCESSIVE ?

HOLE PACKING OFF REACTIVE FORMATIONS MOBILE FORMATIONS UNCONSOLIDATED FORM. INADEQUATE HOLE CLEANING

N

HOLE PACKING OFF REACTIVE FORMATION UNCONSOLIDATED FORMATION

ARE PERMEABLE FORMATIONS EXPOSED ?

N

Y

SURFACE LOAD LIMITATION WITH RESPECT TO LARGER DRAG (ESP. DIRECTIONAL WELL) INADEQUATE HOLE CLEANING (CUTTINGS BEDS) CENTRALISERS BROKEN / BUNCHING

DIFFERENTIAL STICKING

N

Y

FORMATION LEDGES FRACTURED / FAULTED FORM. INADEQUATE HOLE CLEANING CENTRALISERS BROKEN / BUNCHING CASING TOO LIGHT (HAS NOT BEEN FILLED) JUNK IN HOLE

WELLBORE GEOMETRY

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b)

Top drives have been very successful in reducing problems due to tight hole. In exploration areas and known problem areas, consideration should be given to selecting a rig with a top drive unit. The additional cost of such a rig has to be compared with the costs that could result from a fishing job or sidetrack. The decision must be a commercial one.

c)

Ensure that the Rig Contractor’s personnel understand and use BP’s tight hole and stuck pipe procedures.

d)

BHA design should be given careful consideration. A string with only the required components will give the least risk of getting stuck. Many incidents are contributed to by needlessly long assemblies. The number of collars and particularly large OD elements should be justified.

e)

When planning a well, be aware of the amount of open hole time for each section. Any reduction in this will help to cut the chance of stuck pipe.

f)

Mud design is critical in keeping a hole in optimum condition. Careful consideration of the mud system and planned mud weights will be rewarded by reduced tight hole.

g)

Although the first priority for a casing design must be to ensure that the well can be drilled safely, one consideration should be stuck pipe. Without compromising safety, the shoe depth should be planned to case off troublesome formations.

Rig Site Precautions a)

In tight hole situations, be patient. Time spent conditioning mud and the hole is not wasted time, but is insurance against greater time lost during stuck pipe incidents. Circulate sooner rather than later when tripping, if hole conditions are worsening. A Driller may be reluctant to break circulation and disturb the slug, but it is far easier to re-slug the pipe than to free it once stuck.

b)

Keep the drill string moving as much as possible in open hole.

c)

Always ensure that the Drillers are aware of what to do if the hole becomes tight and of any expected problems.

d)

At the first signs of tight hole, the BP Representative must be called to the rig floor.

e)

Always exercise caution when tripping in open hole. The BP Representative should always be on the floor for at least the first 10 stands out, the last 10 stands in and through any problem sections.

f)

Never try to force the string through a tight spot. Pulling firmly into tight hole may well lead to the string becoming stuck. Take it carefully and do not overpull more than half the weight of the collars below the jars. If this rule is followed, it should always be possible to work the pipe back down. This gives the Driller a figure to work to and will prevent many stuck pipe incidents each year. Depending on the situation, the BP Representative has the option of gradually increasing the overpull, each time checking that the pipe is free to go down. At any stage, the kelly can be picked up or the top drive used to wash down and work the pipe. Never pull more overpull than the weight of the collars, as this will almost certainly result in the string becoming stuck.

g)

Always wash and ream at least the last 3 joints to bottom.

h)

Before tripping, always endeavour to clean the hole. This subject is covered at greater length in Section 2.4.

i)

Minimise time spent in open hole.

j)

Monitor and record the depths and magnitude of torque and overpull, to help assess the condition of the hole.

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k)

Wiper trips should be made regularly, according to predetermined procedures or as hole conditions dictate. Often the wiper trip will be made back into the previous casing shoe, but short trips through newly drilled hole may be all that is required.

l)

All Drilling Supervisors should be well versed in how the drilling jars work. The different mechanisms need to be understood because certain situations may arise which require that knowledge. For example, Dailey mechanical jar settings change with torque, while hydraulic jars have an infinite number of settings depending on the pull. If the string is pulled to the maximum and mechanical jars do not go off, it may be that the amount of overpull needed for the jar to hit has not been reached. With hydraulic jars, it would mean that either the string would be stuck above them or that the tool had failed. The Supervisor must know how each set of jars works to make decisions from this point. Any relevant information should be passed to the Driller.

m) The shale shakers should be monitored regularly by the BP Representative, as well as by the Mud Engineer. The shape, quantity and condition of the cuttings give valuable indications of what is happening downhole. Most Reps already check the shakers at frequent intervals and this practice must be continued. n)

Top drive units have been described earlier as a successful development in reducing stuck pipe incidents. However, it must be recognised that the different drilling techniques require some special procedures and the same amount of care. Problems peculiar to top drives have doubtless been identified by all operations which have used them. One example was highlighted on a UK Land operation, where the use of the top drive actually increased the amount of tight hole. When drilling in singles with a kelly, the newly drilled hole was wiped at every connection. With a top drive, drilling in stands, the new hole was wiped far less frequently. This resulted in poor hole conditions and affected drilling performance. After increasing the frequency of wiping the hole to once every single, hole conditions were significantly better. There is a risk of complacency with top drives, as they are sometimes regarded as being capable of keeping pipe moving, however tight the hole becomes. Consequently, action to improve conditions are delayed or not taken at all. This is the wrong approach; top drives are good, but they are not infallible and tight hole must be treated with the same amount of care as it would be if drilling with a kelly. Top drives are a good tool, but must be used astutely.

o)

On floating rigs, the drill string compensator can play an important role in the prevention of stuck pipe by helping to control sudden movements of the pipe. When drilling, the compensator should be stroked out as far as the heave permits. This prevents the string dropping through a fast drilling break and possibly becoming stuck in an unconsolidated formation. It is especially applicable for top hole sections, where the reaction time to pick up an almost closed compensator can be too slow to save a stuck pipe incident. If tight hole is expected when tripping out of the hole, it can be a good idea to keep the compensator unlocked. This gives the Driller more time to react if he suddenly runs into a tight spot. The small amount of time gained may make the difference between staying free and getting stuck. Be aware that some compensators’ rating may not permit this.

2.3

Differential Sticking

2.3.1

Planning Stage a)

Indicate in the Drilling Programme the presence of any permeable formations which may lead to differential sticking.

b)

Estimate the pressure of the problem formation, using all relevant nearby well data. If good and recent RFT, DST or producing well information is available, state the best estimate of the formation pressure in the programme. If the risk of differential sticking is thought to be high, make this clear in the programme.

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Thick reservoirs can give a high risk of sticking, because of the low formation fluid density. Figure 13 shows how the overbalance can rapidly increase with depth when drilling through a gas reservoir. c)

On an appraisal well where differential pressures are thought to be high across a permeable formation, consider taking a RFT measurement. The risk of getting the logging tool stuck should be taken into account, but this may be outweighed by the value of the information on later wells. The RFT is as useful to a Drilling Engineer as to a Petroleum Engineer.

d)

When differential pressures are known to be high, give careful thought to the logging programme, particularly the number of pad tools. These are always susceptible to becoming stuck and especially those tools with radioactive sources should be used with discretion.

e)

Lubricants considerably reduce the force required to free differentially stuck pipe and should always be used in areas where differential sticking is a possibility. There are a wide range of lubricants available for water based systems. There are also some lubricants for oil based mud systems. In the planning stage, the type of lubricant to be run should be considered. Advice on this subject can be obtained from BPX technical support groups. The drilling programme should state the concentration of lubricant to be used.

f)

The planning stage must consider the type of pipe free agent and the spacer to be used ahead of it. The formulation of the pill must be checked to ensure that it can support barytes and that there is minimum gelling when mixing with the mud. There is a considerable difference in the performance of pipe free agents commercially available. Advice on the type of pill and the formulation must therefore be sought from BPX technical groups. The drilling programme must state: a) The pipe free agents to be used and the quantity to be held at the rig site. b) The spacer and pipe free pill formulation. c) Volumes of each to be pumped.

Note: Displacement procedure and requirements on circulating the pill out are given in 3.2.4. g)

The addition of “bridging” material to the mud can reduce the filter cake thickness and hence reduce the potential for differential sticking. Ground marble should be used in preference to calcium carbonate due to the ability of marble to retain its grind size. A typical concentration for this material is 8.0 ppb. Typical grind size is: D10 D50 D90

13 microns 50 microns 160 microns

The grind size and concentration are guidelines only. In the planning stage, the actual grind size and concentration should be considered in detail. Also in the planning stage, the effect of the addition of this material type on shale shaker screen size selection should be considered. Shaker screens should be selected to prevent a drilled solids build-up. This however is likely to remove the coarse end of the ground marble. This should be replaced whilst drilling ahead. The drilling programme should state the rate of addition whilst drilling ahead to replace that taken out at the shale shakers. h)

HTHP fluid loss must be run on the mud when drilling in an area where the potential for differential sticking is high regardless of the bottom hole temperature.

SUBJECT:

5150

5200

16600

16800

DEPTH (FEET)

DEPTH (METRES)

5100

INCREASE IN OVERBALANCE THROUGH GAS RESERVOIR

5050

GAS BEARING SANDSTONE

200 PSI OVERBALANCE

RESERVOIR PRESSURE

HYDROSTATIC PRESSURE OF MUD AT 1.79 SG (14.9 PPG)

17000

17200

750 PSI OVERBALANCE

5250

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FIGURE 13

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PRESSURE (PSI)

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13200

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12800

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The drilling programme must state the maximum value for the HTHP fluid loss and low pressure fluid loss. 2.3.2

2.4


Continuously track the differential pressure across permeable formations, as accurately as possible. Follow the trends of the D exponent graph, trip gas levels and connection gas levels, whichshould indicate changing pressures.

b)

Keep the mud weight at the lowest safe level. A widely used rule of thumb is 200 psi static overbalance, although conditions will frequently dictate a different figure. Aim to keep differential pressures across permeable formations to a minimum.

c)

Maintain all mud parameters within those specified in the drilling programme. In particular: i)

Maintain HTHP and low pressure fluid loss within specification. These values should as a minimum be measured three times perday.

ii)

Maintain gel strengths at the minimum possible value consistent with suspension and hole cleaning requirements. High gel strengths will prevent the efficient functioning of pipe release agents. The 30 minute gel strength should be measured in addition to the standard 10 second and 10 minute and should not be significantly higher than the 10 minute value.

iii)

Drilled solids content should be minimised.

iv)

Lubricant concentration should be maintained as specified in the drilling programme.

v)

When bridging agents are used, the coarse fraction removed at the shale shakers should be replaced whilst drilling ahead.

d)

Use spiral collars and stabilisation to centralise the BHA in potential problem areas.

e)

Keep the pipe moving at all times. Reciprocating is the preferred motion, as it shows that the pipe is free to trip in and out of the hole. However, when this is not possible (e.g. on connections), rotation is considerably better than leaving the pipe static. Do not programme unnecessary surveys as they are a high risk operation. An MWD surveying tool is less likely to become stuck than a single shot, because the string is stationary for a shorter time. In a high risk area, this alone may justify the additional cost of an MWD.

f)

Differential sticking regularly occurs during a well kill procedure, due to the increased mud weight. Under no circumstances should the fear of becoming stuck dictate the kill weight to be used. However, excessive safety margins are sometimes used in both kill mud weight and circulating pressures. These increase the change of stuck pipe.

Inadequate Hole Cleaning Poor hole cleaning will usually cause hole conditions to steadily deteriorate, rather than having an immediate effect. Consequently, there should be an opportunity to recognise and react to the problem.

2.4.1

Planning Stage a)

In large diameter sections, circulation rates are most important and often need to be kept as high as possible. If pump pressure is a limiting factor, consider the use of large ID drill pipe, short BHAs and minimum quantities of heavy weight drill pipe to reduce the friction losses.

b)

Include in the Mud Programme recommended minimum circulation rates. Advice on calculation of minimum flowrates is available from BPX Technical Centres (refer also to Section 4900/GEN). This process is especially important in hole angles of over 30° when cuttings beds start to form.

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Figure 14 shows how flowrates must change relative to hole angle to maintain cuttings removal. The ideal zones to be in are 1 and 2, whereas a flowrate in zone 5 is a guarantee of tight hole problems. The diagram is schematic and should not be used for planning purposes. As a rule of thumb guide, the annular velocity necessary to get cuttings moving in a well inclined at 30° is about 20% higher than in a vertical well. Between 50° and 60°, the annular velocity needs to be about twice that in vertical holes.

2.4.2

c)

Study offset well data for signs of overgauge hole, which may need to be included in minimum flowrate calculations.

d)

Hole angles between 50° and 60° are the most difficult to clean. Cuttings beds at these angles will tend to slide down the low side of the hole and may accumulate, causing the hole to pack off. The Drilling Programme for wells with these inclinations should highlight this potential.


Prior to starting a trip, the hole should be circulated until it is as clean as is practically possible. A minimum circulating time should be predetermined, but a trip should not be started if there are still significant quantities of cuttings coming over the shakers at that time. It may be beneficial to rotate and reciprocate the string while circulating in inclined wells, as the movement assists hole cleaning by disturbing cuttings beds. There are situations where circulation alone could be maintained for days without the hole being effectively completely cleaned. This may often be the case with cuttings beds or wells with severe overgauge sections. Special tripping procedures may need to be used for this type of well. Solutions such as pumping and backreaming out or the use of undergauge stabilisers in the drillpipe to disturb cuttings beds have been used with success.

b)

Do not permit the flowrate to drop below the minimum required to clean the hole. If a mud pump goes down, stop drilling until it is repaired. Trip back into the shoe if the delay is going to be a long one. Do not drill ahead, expecting to clean the hole at a later stage. It may be too late.

c)

There are several indicators which can identify hole cleaning problems: Excessive overpull on connections and trips. Reduced overpull when pumping. Excessive fill after trips. Erratic and increasing torque while drilling. Lack of cuttings on shakers. These must be recognised and action taken.

d)

In high angle wells, increasing the viscosity and pumping hi-vis pills may not improve hole cleaning. Where cuttings beds have formed, low viscosity pills giving turbulent flow may improve hole cleaning. These should usually be followed by a heavy pill to “sweep” up the disturbed cuttings.

e)

Minimise the amount of overgauge hole, where annular flowrates are reduced and cuttings build-up is most likely to occur. Serious problems may result in the next hole section if a very large casing sump is drilled. Always keep the sump to a minimum. Big safety margins are unnecessary. Other avoidable causes of overgauge hole are: Excessively high flowrates and jet nozzle velocity (washouts). Insufficient mud weight (cave-ins). Incorrect mud formulations (soluble formations).

f)

Control ROP to a level at which the cuttings can be removed. This must be applied to instantaneous ROP, not average ROP (refer also to Section 4900/GEN).

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MAP OF FLOW PATTERNS IN DEVIATED WELLS

ZONE 1

ZONE 2

GOOD HOLE CLEANING WITH MOVING CUTTINGS BED EFFICIENT HOLE CLEANING ZONE 4

SOME HOLE CLEANING, CUTTINGS BED FORMED

INCREASING ANNULAR VELOCITY

ZONE 3 SLOW REMOVAL OF CUTTINGS

ZONE 5 NO HOLE CLEANING

0

30

60

90

WELL INCLINATION (DEGREES)

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g)

Always look at the shakers to get a feel for the effectiveness of the hole cleaning. Does the volume of cuttings seem right for the ROP? Do slugs of cuttings appear followed by very few cuttings? The shakers will give an early indication of a hole cleaning problem.

h)

When a downhole motor is being used in an inclined well, without rotating the drill string, it is probable that the cuttings beds are not being disturbed. If possible rotate the string prior to tripping out of the hole.

2.5

Formation Instability

2.5.1

Planning Stage

2.5.2

Section

a)

Use nearby well records to identify any unstable formations which have caused problems in the past. Highlight them in the Drilling Programme. Overgauge hole shown on caliper logs may indicate sloughing formations. Increasing the planned mud weight may help to control them.

b)

If gumbos or swelling shales are expected, ensure that the mud formulation is designed to cope with them.

c)

Eccentric PDC bits have been used successfully in plastic salts and may be applicable for other tight formations. A bit which drills a hole 1/8” larger than the nominal diameter is usually sufficient.


Unstable formations can give a variety of combinations of the following. Recognise them and respond to them: Drag on trips. Fill on trips. Excessive material on the shakers. Excessive torque. Increasing MBT levels which are not due to mud treatments. Salinity changes in the water phase of oil muds. Out of gauge hole. Shape of the cuttings. Cuttings from an earlier drilled section.

b)

Mud properties must be maintained, particularly in shales. Even if it means tripping back to the shoe, time spent conditioning mud may prevent a stuck pipe incident.

c)

Trip with caution through swelling formations.

d)

Ream each single in tight hole. When using a top drive, pick up midway through each stand and ream. If hole conditions are severe, more frequent reaming may be required. Time spent improving conditions is not time wasted.

e)

A top drive allows tight sections to be tripped through using slow rotation and circulation. After pulling into a tight spot, run back into gauge hole and circulate before backreaming out. Current practice indicates that the pump rate for backreaming should be similar to that used for drilling.

f)

Sections which proved to be tight during a trip out of the hole should always be reamed on the trip in.

g)

Tight hole depths must be logged by the Drillers/Tourpushers.

h)

Drillers should be on the brake when tripping through problem formations, as they will have gained a feel for the hole. Assistant Drillers, Tourpushers and Rig Superintendents should be discouraged from relieving the Driller in open hole.

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i)

At the first indications of tight hole, the Driller should call for the BP Representative and the Rig Superintendent/Tourpusher to go to the rig floor.

j)

Wiper trips should be conducted regularly according to predetermined procedures, with additional trips being made if required.

k)

In tight hole situations, consideration of the stuck pipe risk should be made before dropping a single shot survey.

l)

Never spend unnecessary time in open hole.

Key Seating

2.6.1

Planning Stage a)

Review nearby well data for previous incidents of key seating. Indicate any occurrences in the Drilling Programme.

b)

Where key seating is considered to be a potential problem, ensure that a string reamer or key seat wiper is available on the rig for each relevant hole size.


Ream any severe doglegs, before key seats have an opportunity to develop.

b)

If a key seat is suspected or expected to develop, consider using a string reamer in the drill pipe to wipe the build section or dogleg. The reamer must be larger than the drill pipe tool joint and smaller than the collars.

2.7

Bottom Hole Assembly Changes

2.7.1

Planning Stage a)

2.7.2

:


2.6

2.6.2

Section

Do not plan a stiff assembly to follow a flexible BHA, without flagging in the Drilling Programme that care should be taken when tripping in.


Always gauge bits and stabilisers before and after each trip. Ensure that the correct gauge ring is used for bits, some PDC bits need special rings.

b)

Unless torque records clearly show the point at which the bit gauge became worn, consider reaming the whole of the section drilled by the bit.

c)

When running a BHA of increased stiffness, expect to have to ream. Do not trip into the open hole rapidly.

d)

If the hole is thought to be undergauge, extreme caution must be applied when tripping into the hole.

2.8

Plastic Salts

2.8.1

Planning Stage a)

Eccentric bits have been used successfully to combat the problem of extruding salt formations. The eccentric bit drills a hole which is greater than its nominal diameter, typically by 1/8”. With the larger hole, the salt has to move further, before it sticks the pipe. This gives more time to drill the section before a stuck pipe problem will occur. These bits have been used effectively in the Southern North Sea.

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Increasing the mud weight will increase the pressure on the formation and reduce the tendency of the salt to creep into the well.


On drilling into a salt formation, it is advisable to pull above it immediately and treat the mud and weight up as required. The top 20 metres (60 feet) should be drilled cautiously with constant reaming, unless the formation is well known. Salt saturated muds or oil muds are generally used for drilling salts and often need to be weighted up to balance the formation closing pressures.

3.

FREEING STUCK PIPE

3.1

General Procedures

3.1.1

Initial Steps The first actions taken when the drill string becomes stuck have the greatest chance of success. The Driller should be aware of the following points to help him make the correct response immediately.

3.1.2

a)

If the pipe was moving immediately prior to becoming stuck, always try to move in the opposite direction.

b)

Use the jars as soon as possible, jarring in the opposite direction to the pipe movement before becoming stuck.

c)

Work the pipe to the limits. The BP Representative must ensure that a maximum safe pull is specified for each assembly run. The Contractor’s overpull figures may contain an additional safety margin, because of the understandable concern about protecting the pipe. The BP Representative should be aware of this, but not necessarily constrained by it.

d)

If differential sticking is suspected, work in right hand torque and slump the pipe; if not successful, pull to the maximum. If the bit is on bottom, continue working the pipe by pulling up to the maximum and by jarring. See also Sections 3.2.2 and 3.2.4.

e)

Have the chemicals and mud pits ready to make up a pill.

Job Analysis During the earliest stages of trying to free the pipe, decide what caused it to become stuck. This may well be obvious from the conditions which have existed previously. However, the diagnostic process should not be taken lightly, as an incorrect identification of the problem lowers the chances of successfully freeing the pipe. The following are examples of the type of questions which should be asked, before determining a course of action: a)

Is there a potential well control problem?

b)

What was the operation when the pipe became stuck?

c)

What do the rig’s data recorders show?

d)

What recent changes have been made to the mud properties?

e)

What have the hole characteristics been?

f)

Where has the pipe become stuck?

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3.2

Differential Sticking

3.2.1

Causes Differential sticking can be recognised if:

3.2.2

a)

The pipe was stationary before sticking.

b)

Full circulation is possible.

c)

Permeable formations are known to be open.

d)

There is a significantly overbalanced condition.

Freeing the Pipe Mechanically Working the pipe should start immediately. The best chance of success in fully freeing the pipe will be with the Driller’s first response. If the bit is off bottom, the pipe should be slumped with right hand torque held in it. This technique should be applicable in most cases, as differential sticking usually occurs when the slips are set during tripping or connections. If the bit is on bottom, the only course of action is to pull and jar. Right hand torque should again be applied, to try and get movement to the stuck point. Pipe should be pulled to the maximum limit immediately, using the figure specified by the BP Representative. If the first attempts to free the pipe are unsuccessful, it should be worked in both directions until alternative action can be taken.

3.2.3

Reducing Hydrostatic Pressure Reducing hydrostatic pressure is the obvious way of freeing differentially stuck pipe. However, it is essential that all aspects of well control are considered prior to lowering the hydrostatic head. There are several ways of cutting the pressure on the formation, but no single method is the best in every case. The important factors to bear in mind when choosing how to reduce the hydrostatic are the level of control and speed. Whichever method is selected, it will be most effective if the drill string is in compression. A standard method which may be used on any rig is to circulate the mud system while cutting back the weight of mud. The minimum mud weight must be pre-determined and close attention must be paid to all kick indicators. When diluting mud it may be difficult to identify a slow influx of formation fluids, as the active volume is being increased continuously. If it is impossible to monitor total volume, including that of the diluting fluid, extreme caution must be used. This method has the disadvantage of being slow. On floating rigs, depending on the water depth and mud weight, the hydrostatic can be reduced quickly and safely by displacing the choke line to base oil or water. The well would be shut in with the annular preventer and the choke line opened, so reducing the overbalance. Any influx can be easily spotted and the well made safe immediately. Because the active system mud weight has not been cut, the well could be killed by closing the choke line and opening the annular. If the pipe is not freed on the first attempt, an equivalent mud weight can be calculated from the known, safe hydrostatic. The weight of the mud can be cut and the process repeated until the pipe is free or the minimum hydrostatic has been reached. The method may not be suitable in shallow or very deep water, where the change in hydrostatic caused by displacing the choke line can be negligible or excessive. A third approach to reducing hydrostatic pressure is the U tube method as detailed in Section 6010/GEN. Because of well control concerns, this technique should not be used without consultation with the Drilling Office.

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Spotting Procedures Differentially stuck pipe may be freed by the spotting of pipe release agents. These attack and break down the filter cake reducing the bond between the cake and the pipe. Pipe release agents are generally oil based although recently water based products have also become available.

Note: Some of the pipe release agents have a relatively high pour point. They thus become very viscous at low temperatures making pill preparation difficult. These materials must be stored at temperatures where this cannot occur. The volume of spotting fluid depends upon the size of hole at the stuck point. If sticking has occurred around the collars, then sufficient spotting fluid should be pumped to cover the BHA, allowing for some hole enlargement. It is better to use an excessive amount of fluid rather than insufficient to cover the stuck point. If the jars have failed to go off during the initial attempts to free the pipe, it is possible that the string is stuck above them. In this case it is advisable to perform a stretch test to try and locate the stuck point. Stretch tests are not accurate, but can be helpful if calculated stuck point is close to a known permeable formation. Many pipe free pills are ineffective because they fail to contact the filter cake in which the pipe is stuck. This is because high mud gels make removal of the mud from close to the stuck zone very difficult. The following procedures must be followed to improve mud displacement: a)

The severity of differential sticking increases with time, therefore action must be taken immediately. As well as working the pipe, preparation of the pill should start as soon as sticking is identified. In order to prevent the mud in the hole from developing high gels, mud circulation should be maintained as high as possible while mixing the pill.

b)

A turbulent flow or, as thin a spacer as possible, should be pumped ahead of the pipe free pill. This spacer must be compatible with both the mud and the pipe free pill. Thinners can be used in the spacer, but only at levels which will not cause problems if incorporated into the active mud system. To obtain a stable turbulent flow spacer, it is likely that it will have to be unweighted. Prior to the use of this type of spacer, the effect on hydrostatic head must be considered. An unstable turbulent weighted spacer must not be used.

c)

The most effective method of improving the displacement efficiency of the pipe free pill itself is to increase its density above that of the circulating mud. An increase of 0.1 to 0.2 sg is optimum. In general, an increase of 0.15 sg should be used. The pill rheology should be such that it is capable of supporting the weighting agent for extended periods under downhole conditions. A very high YP, however, will prevent the pill flowing into the narrow annulus close to the stuck zone. A value in the range 15 - 25 is recommended.

d)

The spacer and pill should be placed at the fastest rate possible. This not only improves mud displacement, but also minimises mixing at the interface.

e)

Once the pill is in place, it must be left to soak and the pipe worked at regular intervals until the pipe is freed or the decision made to sidetrack/abandon. Soaking times of at least 12 hours should be anticipated.

Note: The practice of retaining a portion of the pipe-free pill inside the drill pipe and slowly displacing to the annulus during the soak period is ineffective. The slow pump rate used for this practice will result in this fluid going up the wide annulus.

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There is very little benefit in pumping further pills as there will always be the problem of removing gelled pipe-free agent from the stuck zone. It is better to allow the first pill to soak (while working the pipe) for as long as possible. f)

After a pill has been spotted, the pipe should be worked, preferably by putting it in compression. Slack off about 10,000 lbs below the weight of the pipe and put in some right hand torque. The amount of torque should be roughly half a turn for every 300 metres (1000 feet) of pipe above the suspected stuck point. Release the torque and pick up the 10,000 lbs, repeating the cycle every 5 minutes.

g)

If an oil based spotting fluid is used, special precautions must be taken to prevent/minimise discharge to the sea on circulating out. If possible, the pill plus contaminated mud should be isolated when returned to surface and then returned to shore for disposal. If the pill has become “strung out”, then the percentage of oil in the mud must be determined and reported to the onshore drilling group. Advice will then be issued.

3.3

Soluble Formations

3.3.1

Stuck Pipe in Limestone or Chalk If stuck in limestone or chalk, an inhibited hydrochloric acid pill may be spotted around the stuck point. If the pill is going to be successful, then the freeing will take place quickly as the formation is dissolved by the acid. The maximum time for a pill to work is 2 hours. If well control considerations permit, the pill should be spotted with a large water spacer ahead and behind it, as the acid can cause severe mud problems. The formulation of the pill should be supplied by the mud company. The technique may corrode high strength tubulars, which should be inspected after the pipe is freed. Safety measures needed when handling acid are described in the Safety Procedures Manual. These must be followed.

3.3.2

Plastic Salts Stuck pipe in a salt section can usually be freed using a fresh water pill spotted around the stuck point. This dissolves the salt. The stuck point will generally be in the BHA, but similar procedures to those given below may be employed if the string is known to be stuck higher up. Typically a fresh water pill large enough to be spotted across the BHA will be pumped, with an additional 20 barrels to be left in the string. An oil based mud system should have a spacer pumped ahead of the pill containing water and detergent. After the pill is spotted, a couple of barrels should be pumped to move some more fresh water into the hole. Maximum pull should be kept on the pipe while the pill is circulated, so that the string will pull free when sufficient salt has dissolved. The pipe should be freed within 2 hours. If not, pump a second pill. As always when using unweighted spacers, well control considerations are paramount.

3.4

Key Seating

3.4.1

Key Seat Recognition Pipe which is stuck in a key seat can be recognised by the following characteristics: a)

Key seating will only give stuck pipe on the trip out, not the trip in.

b)

Tight hole can be correlated with the downhole positions of the large OD portions of the BHA.

c)

Tight hole will occur at the same depth on trips.

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The hole will circulate freely when the pipe is stuck.

Freeing Pipe If the pipe is stuck, then it must be worked down in order to free it. There will be occasions on which the pipe will be able to move down and be rotated, but cannot be pulled past the key seat. In this situation, the string should be slowly rotated with minimum tension applied, in order to try and work the collars and stabilisers past the key seat.

3.5

When to Give Up Attempts to Free the Pipe After a certain effort has been put into freeing the pipe, the decision has to be made whether to back off or not. There are likely to be four options: a)

Continue attempts to free the pipe.

b)

Back off above the free point and run in with a fishing assembly.

c)

Back off above the free point, plug and sidetrack.

d)

Back off above the free point prior to abandoning the well.

3.5.1

The decision to back off and run in with a fishing string will be made if it is considered to offer an increased chance of success. There are too many variables involved for general guidelines to be given and this choice must be based on the experience of the personnel involved.

3.5.2

The option of plugging back and sidetracking should be taken on economic grounds unless there are exceptional circumstances. Safety or legislative reasons would override a financially based decision. Before giving up on a fishing job, the cost of sidetracking must be calculated. The following elements must be considered: a)

The value of the fish which would be left in the hole and the cost of backing off. The latter will include the cost of the wireline unit for running a free point indicator (if not already run) and back off shot, as well as the rig time used.

b)

The cost of setting a plug to kick off from. This is made up from the rig time needed to run in a cementing string; set the plug; trip out; wait on cement; trip in to tag, test and dress the plug and pull out ready to sidetrack. The cost of the cement job must be included and the risk of a failed plug should be built in to the total. This will have to be estimated from past records. If the failure rate is taken to be 1 in 5, then for every four successful jobs, five are paid for. The real cost of a plug is therefore 25% higher than the cost of one attempt.

c)

The cost of sidetracking and redrilling to the original depth. If no comparable sidetrack has been performed, the redrill cost should be based on the time it took to drill the interval initially.

The total of these elements gives an estimate of the cost of side-tracking. This can be used in the following equation to determine the length of time for which it is cost effective to fish. Economic Fishing Time

=

Cost of Sidetrack * Probability of Fishing Success Daily Costs While Fishing

The most difficult part of the calculation is to decide the probability of a successful fishing job. Local experience is best, but there will be times when there have been insufficient incidents for a probability to be estimated. 3.5.3

The final option to abandon the well will rarely be made by an operational group.

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CALCULATION OF OPTIMUM FISHING TIME

The decision to stop fishing and initiate sidetrack or re-spud operations in most cases is based on minimising the cost of the incident. A statistical analysis of previous incidents has been used to develop a tool to estimate optimum fishing time. An analysis of 209 stuck pipe incidents has resulted in the formulation of the following fishing equation. The equation is based on economics and on statistical analysis. It is recommended that the following summary be used to calculate the optimum fishing time as soon as the pipe becomes stuck. There is also an equation which has been deduced from the statistics analysed to predict sidetrack costs. This equation may also be used to determine the optimum fishing time. Case examples are included in this operational summary of a recent report (November 1990) produced by Drilling and Completions Branch in Sunbury. 1.

2.

RECOMMENDATIONS 1.

The equation should be used to calculate optimum fishing time before sidetrack options are considered.

2.

Alternatively the sidetrack costs can be estimated using the normalised equation. From knowledge of the operations planned, a cost can be calculated. The optimum fishing time can also then be deduced from the cost ratio graph.

3.

The knowledge gained in a development area, from offset data or from the actual situations, should always be considered when deciding if there are any overriding factors that affect the decision to fish for a shorter or longer period of time.

4.

The equation must be ignored if safety considerations or Government regulations call for a different course of action.

CALCULATION OF OPTIMUM FISHING TIME a)

Calculation of Cost Ratio For Potential Sidetrack Cost Ratio

=

1.43R V + 56R + 5D + (7RD/1250) + 7,000 + TR

R

= Hourly Rig Operating Rate (£).

D

= Estimated Measured Depth of Stuck Point (Metres).

V

= Value of Drillstring Below Stuck Point (£).

T

= Time Taken to Drill Original Hole from Stuck Point to Depth where Sticking took place (Hours).

...(1)

Key to derivation of constants used in the equations: 1.43R

-

On investigation of cases when pipe was freed the time taken to get back to the same depth prior to getting stuck consisted of 43 pc remedial work.

56R

-

Time taken for post sticking operations. Severance, cement plug, kick-off etc.

5D

-

Back-off depth related costs.

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Calculation of Cost Ratio for Wells Requiring Respud If failure to retrieve the fish will result in a re-spud and not a sidetrack, the following equation may be used: Cost Ratio

c)

=

1.43R V + Cost of Re-spud

...(2)

Graphical Determination of Optimum Fishing Time (OFT) Using the calculated Cost Ratio, draw a line vertically upwards on the graph, Figure 1, until it meets the curve (i.e. A → B). Draw a horizontal line from this point (i.e. B → C) and read off the value of OFT. This gives the time (in hours) which should be used for fishing before starting a sidetrack.

3.

CASE EXAMPLE (PART 1) JOHN SHAW (BRUCE DEVELOPMENT) WELL 9/9A-A04 (D3) Calculation of Optimum Fishing Time As per formula in Section 2: Cost Ratio R D V T

= = = =

=

1.43R V + 56R + 5D + (7RD/1250) + 7,000 + TR

Operating Rate (£2,059). Stuck Point (1781m). Value of Lost Drillstring (£281,192). Time taken to Drill from stuck point to TD (24 hours).

Therefore Cost Ratio = 0.0061. Hence (reading off graph), Optimum Fishing Time = 23 hours. In this particular case the stuck pipe scenario was such that no rotation or circulation was possible from the point of sticking. Prior to sidetracking the time spent attempting to work the string free was 19.5 hours. This shows that although this formula is based on statistical analysis of historic events, there may be situations in which the drilling team can judge better the probabilities. The drilling team still can estimate probabilities and take advantage of previous experience in known areas in the field as an overriding factor whether to keep on fishing or to opt straight for the sidetrack operation which is still an economic decision. 4.

CALCULATION OF SIDETRACK COSTS Of the 209 stuck pipe cases between January 1987 and June 1990, an analysis was made of all the wells sidetracked. The results led to equations being formulated to give a reasonable sidetrack cost estimate. The cost equation omits certain costs which were deemed to be low in relation to those rig-time related (e.g. special helicopter/personnel costs). The results are as follows: Back-Off/Severance Cost:

17R + 5D + 4000

Trip Out Of Hole:

3R +

RD 1250

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Cementing:

10R +

2 RD + 2900 1250

Dress-Off Trip:

8R +

2 RD 1250

Kick-Off Cost:

18R +

2 RD 1250

Redrill Cost:

Redrill Time x R

The Combined Equation Sidetrack Cost

=

7 RD 56R + 5D + 1250 + 7,000 + Redrill Time.R

...(3)

R = Hourly Rig Operating Rate (£). D = Stuck Point (m). Note: As expected this ties into the Optimum Fishing Time Equation. Cost Ratio

=

1.43 R C

...(4)

where: C = Value of Fish Lost Downhole + Cost to Sidetrack to Original Depth. 5.

CASE EXAMPLE (PART 2) JOHN SHAW (BRUCE DEVELOPMENT) WELL 9/9A-A04 (D3) Leading on from Case Example Part 1, a comparison can be made with the sidetrack costs and the costs determined by the graph. As shown in Section 3, the sidetrack costs can also be used to calculate the optimum fishing time. This calculation has been performed, and a comparison made with that determined by the graph in the Case Example Part 1. a)

Anticipated Sidetrack Costs (£): 56R + 5D + 7 RD + 7,000 + Redrill Time.R 1250 R = £2,059. D = 1781m. Redrill Time = 24 hours.

Note: Redrill Time is the anticipated actual time spent redrilling the section, after kick off - best estimate will often be the time it took to drill the original section. Anticipated Sidetrack Cost = £201,728. The actual anticipated was £285,904.

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The optimum fishing time can be calculated from: Cost Ratio

=

1.43 R C

C = Value of Fish Lost Downhole + Cost to Sidetrack to Original Depth. C = £281,192 + £201,728 = £482,920 (Estimated Cost) C = £281,192 + £285,904 = £567,096 (Actual Cost) Therefore: Cost Ratio = 0.0061 (for the Estimated Cost) Cost Ratio = 0.0052 (for the Actual Cost) From the curve shown below, it can be seen that the difference between the estimated cost optimum fishing time and the anticipated actual cost optimum fishing time is negligible. i.e.

Optimum Fishing Time (Estimated Cost) = 23 hours Optimum Fishing Time (Actual Cost) = 26 hours

For a detailed description on the derivation of the equations, refer to Document No. DCB/75/90/BR, Drilling and Completions Branch, Section 152, November 1990, “A New Fishing Equation”.

SUBJECT:

Optimum Fishing Time - All Data

OFT (hours)

96 84 72 60 48 36

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FREEING DIFFERENTIALLY STUCK PIPE USING THE "U"-TUBE METHOD

INTRODUCTION Differentially stuck pipe is generally associated with one or more of the following conditions:

2.

1.

Mud hydrostatic pressure in the wellbore is greater than the formation pressure at the stuck point.

2.

The formation opposite the stuck point is usually porous and permeable.

3.

A thick, weak filter cake has built up across the formation. A slight mud loss may be noticed.

4.

The pipe (drill collars or casing) has been left stationary for several minutes opposite the porous and permeable zones.

5.

There is free circulation around the stuck pipe.

MINIMISING THE RISK OF DIFFERENTIALLY STUCK PIPE Procedures which minimise the risk of differentially stuck pipe include:

3.

1.

Minimise the pressure differential between the mud column and the formation - the sticking force is proportional to differential pressure.

2.

Reduce the effective formation permeability by controlling the mud properties - i.e. minimise mud fluid loss, and keep the solids content as low as is mechanically and economically practical.

3.

Minimise the contact area of the string against the formation by reducing the number and diameter of the drill collars, using spiral cut drill collars, centralise the drill collars with stabilisers, centralise casing strings with accessories, control the mud filter cake so that it is thin and tough.

4.

Minimise the time the string is static - for example, rotate during connections.

5.

In the planning and drilling of a well consideration should be given to casing off low pressured, permeable formations before penetrating higher pressured formations.

6.

Use an oil based mud and maintain an optimum hydraulic programme.

7.

Do not use a float valve in the string.

THE “U”-TUBE METHOD The object of the U-Tube method is to free differentially stuck pipe safely without losing control of the well. If a water based mud is in use, a weighted mud filter cake destroying agent should be spotted across the permeable interval prior to employing the U-Tube method. However, under certain circumstances it may be determined that employing the U-Tube method as early as possible would be preferable since filter cake agents can take several hours to “tighten-up” the cake to an acceptable degree. A procedure to free a drill string which has become differentially stuck is given below. (N.B. Procedure assumes no float valve is installed.) 1.

If at all possible, attempt to space out so that the top of the string is at a working height above the floor and that the annular preventer is located mid-joint in the drill pipe. On fixed units this is likely to be impossible. However, on semi-submersible units it may be possible to change the draught of the rig to achieve a space-out. Ensure that there is a full opening kelly cock valve made up to the top of the string below the circulating head or kelly.

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2.

While preparing to pump light fluid, the maximum allowable right-hand torque should be worked into the drill string.

3.

Calculations: Step 1

Calculate the heads of base oil or water and mud in the annulus which, when combined, balance the formation pressure at the top of the permeable zone (see page 5 or 8).

Step 2

Calculate the required volume in the choke line and drill pipe/casing annulus to give the head of base oil or water calculated in Step 1.

Step 3

Calculate the head(s) of mud (and air) in the drillpipe that balances the formation pressure at the top of the permeablezone (see page 5 or 8).

Step 4

Calculate the volume of air in the drill pipe above the mud after U-Tubing.

Step 5

Calculate the total volume of base oil or water to be pumped, i.e. the sum of volumes from Step 2 and Step 4.

Step 6

Calculate the differential pressure that will be imposed on any other permeable formations after U-Tubing (see page 5 or 8).

Step 7

Calculate the back pressure held on the choke after displacing base oil or water to the annulus.

4.

Close the annular preventer (with minimum closing pressure) and reverse circulate (with minimum pump pressure) the volume of base oil or water calculated in Step 5 down the choke line. Check the back pressure against the value calculated in Step 7.

5.

With down weight, assuming the pipe is off bottom, and right hand torque applied, vent the drill pipe above the kelly cock through the standpipe to allow air to be sucked into the drill string. Bleed off the back pressure in stages through the choke to the trip tank, allowing the mud level in the drill string to fall. The volume of base oil or water returned through the choke should be closely monitored. If a stripping tank is installed, it can be used for this purpose. Monitor drill pipe to determine whether it is “sucking or blowing”. If heavier mud weights are in use, it may be necessary to crack open a top drive or kelly connection above the kelly cock to allow the drill string to “U”-tube. Work the pipe vigorously between the neutral weight and maximum allowable down weight.

6.

a)

If the pipe is freed, continuously move and fill the drill string with mud (venting the air). Circulate out the base oil or water from the annulus and continue to circulate bottoms up (through the choke if there is a chance of gas being produced). Open the annular and continue to work the pipe.

b)

If the pipe remains stuck (note that release might not be instantaneous - drawdown should be applied for at least 2 hours before the attempt is considered to have failed), the mud should be reconditioned and one more attempt made with a bigger reduction in hydrostatic, however extra caution will be required as this may result in a hydrostatic pressure less than formation pressure. If this second attempt fails it is suggested that the pipe is severed immediately above the stuck point and the well sidetracked. The decision to abandon or continue the fishing attempts will be made by town.

SPECIAL CONSIDERATIONS Factors that should be considered before employing this technique include:

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1.

The amount of open hole and likely effects of sharp reduction in hydrostatic pressure on stability of all exposed formations.

2.

Is there geological closure at the depth of the permeable formation? Is it likely to contain gas or oil?

3.

Are there any other permeable zones exposed? What effect will the reduction in mud head have on them?

4.

How much confidence is there in the accuracy of formation pressure estimates?

5.

The volumes of base oil or water required - this might necessitate modification to the procedure.

6.

How much confidence is there in the pressure control equipment and personnel?

VARIATIONS OF THE “U”-TUBE METHOD Variations on the standard technique include: 1.

When the volume of base oil water required presents insurmountable handling problems (perhaps where the annular area is large, or the height of the choke line available is small), the base oil or water can be pumped to drill string to induce a drop in annulus level after U-Tubing. However, this provides less control over the operation (unable to ascertain the level in the annulus) and incurs a greater chance of plugging the bit. In this instance it may be advisable to reduce the mud weight in the whole system such that when U-Tubing is initiated then the drop in the annulus level will be reduced.

2.

When there is a float valve in the drill (or casing) string and there is considerable height of choke line available, the choke line can be displaced to base oil or water, the annular preventer closed and the preventer would support the hydrostatic pressure in the riser sufficiently to allow the premeable formation to be drawn down.

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CALCULATIONS (METRIC UNITS) KNOWN DATA Pf

=

The formation pressure at the top of the permeable zone.

psi

D

=

The true vertical depth of the top of the permeable zone.

m

SGm

=

The mud density.

SG

SGf

=

The fluid density of the base oil or water.

SG

SGa

=

The density of air.

0.001 SG

Lcl

=

Height of the choke line.

m

Ccl

=

The capacity of the choke line.

bbl/m

Cann

=

The capacity of the drill pipe/casing annulus.

bbl/m

Cdp

=

The capacity of the drill pipe.

bbl/m

CALCULATIONS REQUIRED (Refer to Figure 1) STEP 1 Calculate the heads of base oil/water and mud in the annulus after “U”-Tubing (i.e. after flowback). P ( 1.421 ) - (D x SG ) f

X2

m

=

(SGf - SGm) Y2

=

where:

D - X2 X2

= The head of base oil or water in the annulus (m).

Y2

= The head of mud in the annulus (m).

STEP 2 Calculate the required volume of base oil/water in the choke line and drill pipe/casing annulus to give the head of base oil calculated in Step 1. V

=

where:

(Lcl x Ccl ) + ( (X2 - Lcl ) x Cann ) V = Volume of base oil/water (bbl).

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STEP 3 Calculate the heads of air and mud in the drill pipe after “U”-Tubing. P ( 1.421 ) - (D x SG ) f

A

m

=

(0.001 - SGm) B

=

where:

D - A A

= The head of air in the drill pipe (m).

B

= The head of mud in the drill pipe (m).

STEP 4 Calculate the volume of air in the drill pipe above the mud after “U”-Tubing. Vair

=

A x Cdp

(bbls)

STEP 5 Calculate the total volume of base oil/water required to obtain the head of oil/water after displacement. Voil

=

V + Vair

where: Voil = The total volume of oil/water required (bbl). STEP 6 Calculate the maximum drawdown imposed on any other permeable formations after “U”-Tubing. ∆P

=

Pf - Phyd

where:

Phyd

=

Pf

=

Formation pressure at the other permeable formation.

Phyd

=

Hydrostatic pressure due to the fluids in the annulus after “U”-Tubing.

(X2 x SGf x 1.421) + ((D2 - X2) x SGm x 1.421)

N.B. If D2 is less than X2, then: Phyd = D2 x SGf x 1.421

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STEP 7 Calculate the back pressure held on the choke after pumping the base oil or water. Pchoke

=

(D x SGm x 3.281 x 0.433) - ((Y1 x SGm x 3.281 x 0.433) + (X1 x SGf x 3.281 x 0.433))

X1

=

X2

+

Vair Cann

Y1

=

Y2

-

Vair Cann

(D

=

X1 + Y1)

where:

Pchoke

=

Backpressure on choke (psi).

X1

=

The head of base oil or water in the annulus after pumping the base oil or water (m).

Y2

=

The head of mud in the annulus after pumping the base oil or water (m).

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CALCULATIONS (IMPERIAL UNITS) KNOWN DATA Pf

=

The formation pressure at the top of the permeable zone.

psi

D

=

The true vertical depth of the top of the permeable zone.

ft

PPGm

=

The mud density.

ppg

PPGf

=

The fluid density of the base oil or water.

ppg

PPGa

=

The density of air.

0.01 ppg

Lcl

=

Height of the choke line.

ft

Ccl

=

The capacity of the choke line.

bbl/ft

Cann

=

The capacity of the drill pipe/casing annulus.

bbl/ft

Cdp

=

The capacity of the drill pipe.

bbl/ft

CALCULATIONS REQUIRED (Refer to Figure 1) STEP 1 Calculate the heads of base oil/water and mud in the annulus after “U”-Tubing (i.e. after flowback). P ( 0.052 ) - (D x PPG ) f

X2

m

=

(PPGf - PPGm) Y2

=

where:

D - X2 X2

= The head of base oil or water in the annulus (ft).

Y2

= The head of mud in the annulus (ft).

STEP 2 Calculate the required volume of base oil/water in the choke line and drill pipe/casing annulus to give the head of base oil calculated in Step 1. V

=

where:

(Lcl x Ccl ) + ( (X2 - Lcl ) x Cann ) V = Volume of base oil/water (bbl).

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STEP 3 Calculate the heads of air and mud in the drill pipe after “U”-Tubing. P ( 0.052 ) - (D x PPG ) f

A

m

=

(0.01 - PPGm) B

=

where:

D - A A

= The head of air in the drill pipe (ft).

B

= The head of mud in the drill pipe (ft).

STEP 4 Calculate the volume of air in the drill pipe above the mud after “U”-Tubing. Vair

=

A x Cdp

(bbls)

STEP 5 Calculate the total volume of base oil/water required to obtain the head of oil/water after displacement. Voil

=

V + Vair

where: Voil = The total volume of oil/water required (bbl). STEP 6 Calculate the maximum drawdown imposed on any other permeable formations after “U”-Tubing. ∆P

=

Pf - Phyd

where:

Phyd

=

Pf

=

Formation pressure at the other permeable formation.

Phyd

=

Hydrostatic pressure due to the fluids in the annulus after “U”-Tubing.

(X2 x PPGf x 0.052) + ((D2 - X2) x PPGm x 0.052)

N.B. If D2 is less than X2, then: Phyd = D2 x PPGf x 0.052

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STEP 7 Calculate the back pressure held on the choke after pumping the base oil or water. Pchoke

=

(D x PPGm x 0.052) - ((Y1 x PPGm x 0.052) + (X1 x PPGf x 0.052)

X1

=

X2

+

Vair Cann

Y1

=

Y2

-

Vair Cann

(D

=

X1 + Y1)

where:

Pchoke

=

Backpressure on choke (psi).

X1

=

The head of base oil or water in the annulus after pumping the base oil or water (ft).

Y2

=

The head of mud in the annulus after pumping the base oil or water (ft).

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EXAMPLE CALCULATION KNOWN DATA The drill string is suspected to be stuck across a permeable zone. The top of the stuck zone is thought to be 4000m. Last casing = 9 5/8”, 47 lb/ft at 3600m. D = 4000m. Pf at 4000m = 8800 psi. Cdp

=

0.0587 bbl/m.

Cann

=

0.1604 bbl/m (5”/9 5/8” casing).

SGm

=

1.6 SG.

SGf

=

0.8 SG.

Lcl

=

100m.

Ccl

=

0.0128 bbl/m.

Objective: To reduce the hydrostatic at the top of the stuck point to the formation pressure of 8800 psi. STEP 1 Head of base oil in annulus (X2). X2

=

(8800/1.421) - (4000 x 1.6) 0.8 - 1.6

=

258.75m

Head of mud in annulus (Y2). Y2

=

4000 - 258.75

=

3741.25m

STEP 2 Volume of base oil in choke line and drill pipe/casing annulus. V

=

(100 x 0.0128) + ((258.75 - 100) x 0.1604)

=

26.74 bbl

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STEP 3 Heads of air and mud inside drill pipe after “U”-Tubing. A

B

=

(8800/1.421) - 4000 x 1.6 0.001 - 1.6

=

129.6m

=

4000 - 129.6

=

3870.4m

STEP 4 Volume of air in drill pipe after “U”-Tubing. Vair

=

129.6 x 0.0587

=

7.6 bbl

STEP 5 Total volume of base oil required. Voil

=

26.74 + 7.6

=

34.34 bbl

STEP 6 A second permeable zone exists below the shoe at 3700m. The estimated pore pressure is 8000 psi. Phyd

∆P

=

(258.75 x 0.8 x 1.421) + ((3700 - 258.75) x 1.6 x 1.421)

=

8118 psi

=

8000 - 8118

=

-118 psi

i.e. still overbalance, no drawdown.

STEP 7 Back pressure on choke after displacing the annulus to base oil. X1

=

258.75 +

=

306.13m

7.6 (0.1604 )

BP EXPLORATION


Y1

Pchoke

3741.25 -

=

3693.9m

7.6 (0.1604 )

(4000 x 1.6 x 3.281 x 0.433) - ((3693.9 x 1.6 x 3.281 x 0.433) + (306.13 x 0.8 x 3.281 x 0.433))

=

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=

=

Section

347.95 psi

BASE OIL

D

MUD

Y1

STUCK

CSG

D

Y2

MUD

X2

BASE OIL

FREE?

CSG

D

P CHOKE 0 psi

MUD

0 psi

A

DRILLING MANUAL

STUCK

CSG

X1

MUD

MUD

BASE OIL

MUD

MUD

P CHOKE

MUD

MUD

0 psi

0 psi

MUD

MUD

3. AFTER FLOWBACK

AIR

MUD

2. AFTER DISPLACING

MUD

MUD

SUBJECT:

MUD

1. BEFORE DISPLACING

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SEQUENCE OF BASE OIL DISPLACEMENT TO FREE DIFFERENTIALLY STUCK PIPE

FIGURE 1

2179 /142

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FREEING STUCK PIPE WHILST DRILLING RISERLESS AND FROM FIXED INSTALLATIONS

STUCK PIPE INCIDENT WHEN DRILLING TOP HOLE RISERLESS A similar procedure can be used on jack-ups and platforms. On fixed installations the stuck string is supported at the rotary table with elevators. The washout string is then run as outlined below. Example: Drilling 17 1/2” hole. The string packed off, no rotation or circulation was possible and jarring failed to free the stuck pipe.

2.

A procedure to free the stuck pipe, by running a washout string into the stuck drilling assembly/open hole annulus and circulating free has been developed.

3.

EQUIPMENT PREPARATION AND OPERATIONAL PROCEDURE Hang the stuck string off underneath the rotary table using the riser tensioning system.

3.1

Check the weather forecast. If bad weather is imminent pospone the operation until the weather improves. HOLD SAFETY MEETING WITH CREW. SAFETY LINES MUST BE USED AT ALL TIMES. ENSURE WALKWAYS AROUND MOONPOOL AREA ARE SECURE.

3.2

Attach a set of 350 ton elevators to 2 riser tensioning wires with 50 ton shackles.

3.3

Latch elevators around stuck pipe at most accessible tool joint underneath rotary table. Do not tension up the Rucker wires at this stage. Back off tool joint above elevators. Two methods can be used.

3.4

Method 1

3.4.1

Attach tongs in moon-pool area to rig floor tugger wires or pod line wires. Break connection with tongs.

3.4.2

Remove tongs and tension up Rucker wires to support stuck string. Ensure shackles securing the elevators to the Rucker wires are not snagged and fit snugly underneath elevator ears. No load should be acting on hinge pin or ear brackets. Position a man on the spider deck to keep a watch on the elevator and tensioning system.

3.4.3

Back out string above rotary table with chain tongs.

3.5

Method 2

3.5.1

Using the top-drive, torque up the joints in the stuck string above the rotary table to maximum for the pipe in use. Position back-up tong on pipe to prevent torqueing up joints below rotary table.

3.5.2

Position back-up tong on joint to be broken under rotary table.

3.5.3

Crack the tool joint with the top drive.

3.5.4

Tension up Rucker wires to support stuck pipe. Precautions as for 3.4.2 above.

3.5.5

Using the top-drive, break out joint below rotary table. Important Points to Note With the rig heaving, the jars in the stuck pipe assembly may cock. If the jars fire, reconnect the drillstring and let off weight on the pipe.

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Be aware if the elevators fail or the string falls sideways, damage to the pontoons or cross bracings of the semi-submersible may occur. 3.6

Connect a circulating head and chicksans to the hung off pipe. Rig up a circulation system to enable simultaneous circulation down the stuck drilling string and the washout string.

3.7

Make up and run 150 metres of 3 1/2” tubing.

3.8

Run the tubing into the annular space between the stuck pipe and open hole on 5” drill pipe. Circulate the washout string down to the first stabiliser pumping hi-vis pills.

3.9

During running and circulating through the washout string, attempt to pump down the stuck string. Ensure full mud returns to the seabed from the stuck pipe. If in any doubt about returns, stop circulating down the stuck string. The formation may become fluidised, causing further problems of washouts or hole caving.

3.10

Continue running the washout string down to the bit if necessary.

3.11

With the stuck string under tension, once the hole has been washed out down to the stuck point, the string and drilling assembly will come free. Immediately the stuck pipe comes free, break circulation carefully down the free pipe. Increase pump rate when full returns are gained. Pump round a 50 bbl hivis pill down the drilling assembly.

3.12

Pull out the washout string whilst maintaining full circulation down the drilling assembly.

3.13

Rig down the circulating head, reconnect pipe to the top-drive or Kelly.

3.14

Break circulation, rig down elevator and Rucker tensioning system and resort to normal drilling operations.

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ROTARY TABLE

STUCK STRING

WASHDOWN STRING

Fig 2.0

Elevators Dressed with 50 Ton Shackles

SEABED (162mbrt) 36" HOLE

210mbrt 3.1/2" TUBING

ROTARY TABLE

362mbrt

RUCKERS

562mbrt Fig 1.0 Situation on becoming Packed-Off

STUCK STRING ATTACH TONG TO TUGGERS SUCH AS TO ALLOW BREAK-OUT OF THE TOOL JOINT

SECURE TONG TO PAD EYES ON DECK TO ALLOW BREAK-OUT OF TOOL JOINT

ELEVATORS

WALKWAYS (SECURE IN PLACE BEFORE USE)

BEAMS

Fig 3.0 Diagram Showing Set-Up for the Break-Out of Tool Joint

910035

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JAR PLACEMENT AND JARRING PRACTICES

JARRING Two phenomena have to be considered when jarring: a) impact; and b) impulse. The impact force must be high enough to break the binding forces causing the pipe to stick and that force must act long enough to move the fish. This is termed the impulse force. Both forces are influenced by the amount of drill collars placed above the jar. The smaller the quantity of drill collars placed above the jar, the higher the impact force. Conversely, the larger the quantity of drill collars above the jar, the greater the impulse. Clearly a compromise has to be reached where impact and impulse are operating together to reach the common objective, i.e. to free the stuck pipe. A comprehensive report has been published, “A Review of Jar Placement”, which discusses the theory and practicalities of correct jar positioning. This report should be read and used in conjunction with the JARPRO computer guide to optimise jar placement and to check on loadings available from various jar/drill collar combinations. Copies of both documents can be obtained from the fields’ SDEs.

2.

JARS AND JARRING PRACTICES There are two types of jars: mechanical and hydraulic. Mechanical jars are preset at surface. Hydraulic jars are adjustable for overpull downhole. In general, an increase in jar stroke length increases both impact and impulse. With these obvious advantages, a long stroke, hydraulic jar should always be used if possible.

2.1

Jar Placement 3 - 4 drill collars should be placed above the jar. BHA components should not be mixed, e.g. if using 8” drill collars below the jar, use 8” collars above. If the BHA has to be modified, e.g. to reduce differential sticking, consider running 6 1/4” collars instead of HWDP. Jarring performance will be reduced if there is a large difference between the collar/HWDP size above and below the jar. Do not drill with the jars at their neutral point. A minimum of 5,000 lbs tension or down-weight should be used.

2.2

The Effects of Circulating When Jarring When circulating, pump open forces greatly influence jarring performance and have to be carefully considered. a)

Jarring Up with a Hydraulic Jar: Circulating makes the jar harder to cock but when the jar does trip both impact and impulse forces are increased. To be confident that the jars are cocked, slack off more weight or stop circulating.

b)

Jarring Up with a Mechanical Jar: The jar will trip with less overpull and is harder to cock.

c)

Jarring Down with a Hydraulic or Mechanical Jar: The effects are less easily identified and circulating does not influence impact values. Cocking the jars is easier but the jar is harder to trip.

3.

JARRING PRACTICES Visually check derrick for loose fittings. All personnel to be kept clear of derrick and drill floor when jarring. As a rule of thumb, jar up going in the hole and jar down when pulling out. Uncock the jar

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JAR PLACEMENT AND JARRING PRACTICES

before working pipe in tight hole. When drilling with the jars in compression, uncock the jar before making a connection. This will prevent any sudden, unplanned upward jarring. When jarring, overpull to the maximum figure to trip the jar, wait for the jar to trip THEN increase the overpull to that recommended for the pipe. If the string is overpulled to the maximum recommended for the pipe before the jar has tripped, severe overloading of the jar may occur causing catastrophic failure of the jar. When the drill string is initially stuck, start jarring with 40 - 50,000 lbs overpull above that to trip the jar. Increase overpull to maximum over a one hour period.

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EFFECTIVE PULL ON STUCK PIPE

1.

GENERAL

1.1

Prior to pulling or jarring on stuck drillpipe or casing, the following preparations must be undertaken: a)

Ensure that all surface pulling equipment is in good working condition, and do not exceed the maximum allowable safe working rating of the weakest link in the pulling equipment.

b)

Check the weight indicator and deadline anchor for the following: i) ii)

Sensator gap. Dead Man Anchor gap.

Ensure both are correct and clear of cement and debris. 1.2

Pull should be limited on stuck pipe to 85% of the minimum yield strength of the weakest member, unless differently advised by the drilling office.

2.

EFFECTIVE PULL ON STUCK DRILL PIPE When determining the pull on Stuck Drill Pipe the actual weight of the string in air is to be used and not the indicated weight as recorded by the weight indicator. Example: Depth - 9765 ft

3.

Weight of Drill Collars in Air = 743’ of 6 1/2” OD x 3” ID Drill Collars = 743 x 89 Weight of Drill Pipe in Air = 9022’ x 19.5 lb/ft

= =

66100 lbs 175900 lbs

Total Weight of String in Air

=

242000 lbs

Indicator Reading Weight of Hook, Blocks, Swivel, etc.

= =

205000 lbs 27000 lbs

Pull Reported at 100,000 lbs over Indicator Reading Less Hook, Block, Swivel, etc.

= =

305000 lbs 27000 lbs

Effective Pull on String

=

278000 lbs

Assuming that pipe is stuck on bottom then the effective pull at the stuck point = 278000 - 242000 (no buoyancy of pipe)

=

36000 lbs

In order to apply a pull of 100,000 lbs at the bit, the Indicator Reading would have to be 242000 + 27000 + 100000

=

369000 lbs

This would mean that the pull on the pipe amounts to 369000 - 27000

=

342000 lbs

STUCK CASING The maximum total surface load (NOT overpull) on casing should not exceed either: 1. or

Yield Strength of Top Pipe or Thread (take weakest) 1.6

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Yield Strength of Weakest Pipe or Thread 1.6

+ (Weight in Air of Casing above it)

whichever is the lower. EXAMPLES 1.

13 3/8” casing - N80 - 72 lbs/ft - Buttress Yield Strength of the Pipe Yield Strength of the Thread Maximum Total Load

2.

=

= =

1661000 lbs (weakest) 1693000 lbs

166100 1.6

=

1038125 lbs

9 5/8” casing - P110 - 47 lbs/ft - Buttress from 0’ - 3000’ 9 5/8” casing - N80 - 47 lbs/ft - Buttress from 3000’ and deeper pipe is stuck below 3000 ft. Yield Strength P110 Pipe Yield Strength P110 Thread Yield Strength N80 Pipe Yield Strength N80 Thread

= = = =

Maximum Total Load is either:

1493000 lbs 150000 lbs 1086000 lbs 1161000 lbs 1493000 1.6

=

933125 lbs

or: 1086000 + (3000 x 47) 1.6

=

819750 lbs (which is lower one in this case).

Note: a)

Regardless of the calculated allowable loads, the safety factor for the blockline must never be less than 3. This may well be the limiting factor instead of the casing strength.

b)

If there are angle changes in the hole and/or internal pressure inside the casing, the allowable surface load will be restricted. These values are given in API bulletin 5C2. For angle changes only, the reduction in allowable load can be calculated as follows: Reduction in allowable load = 63 x D x W x A pounds where:

c)

D = diameter of pipe, in inches. W = weight of pipe per foot, in pounds (below angle change). A = angle change, in degrees/100 ft.

If the casing is stuck in such a way that no circulation is possible, the string can be pressurised and then be bled off (before applying extra pull), thus providing below the floats upward force in addition to the pull applied at surface. At all times the effect of increased pressures on formation breakdown gradients must be considered.

A rule of thumb for determining the pipe body yield strength of casing is as follows: F = 0.29 x W x Y pounds where:

W = weight of casing in lbs/ft. Y = yield stress in psi.

BP EXPLORATION



Example Take new 7” casing - C75 - 32 lbs/ft Min yield is 0.29 x 32 x 75000 = 698800 lbs Halliburton book gives: 699000 lbs

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Optimum Fishing Time 6005/GEN

YES

Back-Off above Jars

YES

NO

NO

Determine Free Point & Neutral Weight at Free Point page 14 (7)

Is Back-Off possible ?

YES

Torque String to right for d.p. Make-Up Page 13 (5)

Run Back-Off Charge to Depth

Work in Left Hand Torque Page 18 (9)

Adjust String to Neutral Wt.

Final Wireline Correlation for Back-Off Charge

NO

Run Severance Charge to Depth

Fire Back-Off Charge NO

Pull Max on String Pressurise String if possible

NO String Backed-Off ?

POOH String

6150/GEN

Circ Hole Clean

:

YES

Section

String Free ?

5 (10/92)

NO

:

Did Equipment perform ?

Rig Down Wireline

Rev.

NO

1 of 24

Final Correlation Fire Charge

YES

YES

Circ, Move String whilst POOH Wireline

:

YES

String Free ?

Page

Work Pipe ReTorque to Left Page 14 (3)

BP EXPLORATION

Jars Working ?

DRILLING MANUAL

Rig Inventory FPI/Back-Off Tools Severance Explosives

FREE POINT DETERMINATION AND BACK-OFF PROCEDURES

FREE POINT, BACK-OFF & SEVERANCE OPERATIONS FLOWCHART

SUBJECT:

STUCK PIPE

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Find the free point and determine the connection to be backed off by either: 1) 2)

Stretch Test. Free point indicator run on wireline.

When the connection to be "backed off" has been determined, the procedure to back off either with or without the help of an explosive charge will be advised from the Shore Base. 1.

The Stretch Test is only used in straight hole and can only be applied on semi-submersible units if there is no significant heave. It is an inaccurate method of determining the stuck point and should be used as a rough guide only. When doing the stretch test: 1.

Mark the string at the rotary table "A", the string pull should be the weight of the string in air.

2.

Pull additional tension and measure the stretch in the string by the rise of the mark from the rotary table. Mark the pipe at the rotary table "B".

3.

Lower the string to the original Martin Decker reading. Re-mark the pipe at the rotary table "C". This mark will be different from the original starting mark.

4.

Pull the same additional tension as in 2, and again measure the stretch, re-mark the pipe at the rotary table "D".

5.

Measure the distance from: The mid-point of the bottom two marks to: the mid-point of the upper two marks. Mark D Mark B "e" Mark C Mark A The distance "e" will be the stretch of the pipe.

6.

The relationship between stretch and free length will be: L1

=

where:

E x e x Wdp 40.8 P E e Wdp P

= = = =

Modulus of elasticity = 30 x 106 Differential stretch (inches) Weight per foot of pipe in air (lbs/ft) Differential pull (lbs)

Note the stretch test is accurate only to 200 - 300 ft (60 - 90m) in deeper holes and less accurate in shallow holes.

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FREE POINT DETERMINATION AND BACK-OFF PROCEDURES To accomplish a successful back-off an understanding of why the string got stuck, knowledge of the borehole shape and all past and present hole problem areas is required. Armed with this information and careful interpretation of the free point indicator results will help to achieve a successful operation. If the decision to back-off has been taken it is strongly recommended that a free point indicator (FPI) tool should always be run to determine the stuck point. If the jars in the assembly are still stroking and it has been decided to back-off at or above the jar, then there is no need to run the FPI. Check the jar tensile rating - "necking" of the jar mandrel can occur when applying large overpulls. If necking occurs it may prevent passage of wireline tools through the jar. The FPI can measure stretch and torque. It should be possible to back-off pipe when torque and stretch measurements indicate 80 - 85% of free pipe readings.

3.

FREE POINT INDICATOR TOOLS Electric logging free point indicators require the string to be tensioned and torqued, thereby activating the tool's strain gauges. In general, back off attempts will be made on the lowest connection where torque and stretch readings are 80% to 85% of free pipe. The Drilling Supervisor should familiarise himself with the operation of the logging contractor's tools. The following text explains Schlumberger's FPI tools.

3.1

SIT-C (Stuck Point Indicator Tool) This tool is anchored to the inside of the pipe with 2 sets of bowspring anchors spaced approximately 4 feet apart. The tool is suited for use in shallow wells where heaving of the drilling vessel may cause slippage of the tool. The bowsprings can move up the pipe with the heave without damage. There is the facility to include "slip joints" in the tool suite to compensate for vessel heave. The bowsprings diameter is changed by adjusting the holding nuts on either side of the spring. To take measurements in drill pipe and drill collars the wireline has to be tripped and the bowsprings adjusted at surface. Stretch and right-hand torque can be measured. The results are defined by measuring the air gap between 2 magnets after the pipe has been put under tension or torque. The tool cannot distinguish between stretch and torque, thus all residual torque or stretch must be out of the pipe before further measurements are made.

3.2

SIT-F This tool is equipped with 2 sets of hydraulically operated arms spaced approximately 4 feet apart. Each set has 3 arms. Each arm's tip is coated with hard facing which prevents slippage of the tool. If measurements have to be made inside drill pipe and drill collars the wireline has to be tripped and the arms changed at surface to accommodate the different ID's. The principle of operation is identical to the SIT-C above.

3.3

FPIT (Free Point Indicator Tool) This tool has 2 sets of hydraulically operated arms as in the SIT-F tool. Arms can be installed to anchor in ID's ranging from tubing up to 17 1/2" casing. The hydraulic force holding the arms to the inside of the pipe is substantially greater than in the SIT-F tool. There are 2 sensors, one for measuring stretch and one for measuring both RH and LH torque. The principle of measurement involves Kelvin transfer: measuring the field between 2 receivers and a transmitter.

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A combination FPI measurement and back-off charge run can be made with the FPIT tool, see page 17 for chart. This assembly has limited application. See Section 8 - Running the Back-Off Charge.

Note: All Schlumberger tools are 1.375" OD. The following text explains Atlas FPI tools. 3.4

Atlas FPI Tool (2501) Atlas use three types of FPI. The Atlas freepoint indicator comes in 5 separate sections. Two motor sections, one sensor, one electronics and one ccl section, i.e: Bottom-Motor-Sensor-Electronics-Motor-CCL-Top The tool will lock itself firmly in place with the tungsten carbide tipped anchors and can be used in all sizes of drillpipe. The design of the tool, slick, makes it ideal for both low and highly deviated holes. Pump down is possible. The logging cable can be totally slacked off while performing readings. A real time ccl and freepoint (freepipe percentage) log will be recorded in the field.

Note: 2501 FPI tool 1.300" OD. 3.5

The AES FPI Tool (2502) The AES freepoint indicator comes in 5 separate sections. Two anchor sections (bow springs), one sensor section, one ccl, one slip joint, i.e: Bottom-Anchor-Sensor-Anchor-CCL-Slip Joint-Top The tool is supplied with its own panel (2504), the tool locks itself in place with tungsten carbide tipped bowspring anchors. The tool is designed for hostile environment wells and does not contain electronic components. The bowspring anchors must be set up for pipe ID +0.5". Two sizes of slip joint are available, 3 ft and 9 ft length, to compensate for heave and cable slack. The best results for this tool are achieved in deviations of less than 45 deg. The tool is not recommended for hole angles greater than 60 deg.

Note: 2502 FPI tool 1.375" OD. 3.6

The Magnatector FPI Tool (2515) The Magnatector freepoint indicator comes in one piece. The tool is always supplied with its own panel (2509). The tool locks itself in place with surface powered electromagnets. The design of the tool, slick, makes it ideal for high deviation wells, pump down is possible. The magnets will lock the tool in ANY SIZE OF DRILLPIPE OR CASING. The logging cable can be totally slacked off while taking readings.

Note: 2515 FPI tool 1.438" OD. 3.7

Surface Checks 2501 FPI 1) 2)

Operate arms check/set for appropriate max. diameter. Check sensor for response under tension/compression, LH/RH torque.

BP EXPLORATION

DRILLING MANUAL SUBJECT: 3)

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Check CCL.

2502 FPI 1) 2) 3)

Set bowsprings for pipe ID plus 0.5". Check sensor response under, tens/compression, LH/RH torque. Check CCL.

2515 FPI 1) 2)

Activate magnets against metal surface. Check sensor response under, tens/compression, LH/RH torque.

Note: All these Atlas tools will record stretch or torque but cannot distinguish between them. All tools are maintenance free while on the rig. 4.

MECHANICAL SURFACE CHECKS FOR ALL TOOLS

4.1

The SIT-C and the SIT-F tools have oil filled diaphragms to compensate for hydrostatic pressure. The diaphragms have to be properly filled prior to running the tool. Incorrect oil-level is the most common cause of failure. The FPIT tool has no diaphragm.

4.2

Operate the arms and check maximum diameter with ring gauge.

4.3

On bowsprings, set diameter to 1/2" to 3/4" greater than pipe to be measured and check same against a ring gauge.

5.

INTERPRETATION OF FREE POINT INDICATOR RESULTS The free point is selected as the deepest point at which the pipe can be backed-off and recovered. Both stretch and torque readings are required to make absolutely sure the pipe is free. The pipe may be free in torque but not in stretch, e.g. when a stabiliser has a rock lodged above it. Careful and thorough interpretation of the free point indicator results has to be made. The most common fault is not to take enough time to work the torque down to the measurement point. In the past odd readings obtained when using FPI tools were blamed on the tool slipping in the pipe whilst the measurements were being taken. It is highly unlikely that the FPI tools are slipping inside the pipe, if the anchors are deployed and there is sufficient cable slack.

5.1

Examples in Interpretation of Different Hole Geometries The following diagrams illustrate the hole conditions and the stretch and torque readings of typical FPI runs to determine the free point. If the stretch and torque readings are 80 - 85% of free pipe, back-off, if performed correctly, is certain. For a successful back-off 3 conditions are absolutely essential: a)

Neutral Weight at Connection to be Backed Off This weight has to be carefully calculated accounting for hole friction or as observed using FPIT tools (see page 15, para. 7.8).

b)

Correct Amount of LH Torque at Connection to be Backed Off Time has to be taken to work in the torque and positive indications observed that the torque is going downhole and being applied to the connection to be backed off. When taking the initial

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stretch and torque readings to determine the free point, an indication will have been gained as to the degree of difficulty in getting torque down to any particular connection. If the pipe can be torqued up to the right, then the pipe can be torqued to the left to the same degree. (For the backoff, LH torque should not exceed 80% of the make-up torque.) In top-drive units, rig up wireline through gooseneck bull plug access or remove gooseneck and washpipe. Working pipe to get LH or RH torque down to the free point is far easier and more safely done with the top-drive connected to the drill string. c)

Correct Quantity of Primer Strands for Back-Off Explosive Figure 6 on page 18, indicating the correct quantity of primer chord to be used, should be referred to when making up the explosive charge.

The following 4 stuck pipe examples give an idea how difficult it can be to accurately interpret FPI readings in both stretch and torque. Care should be taken when carrying out the initial FPI readings. They can give a good indication of hole drag and the ability to transmit torque downhole. This is essential when selecting the correct neutral weight prior to backing off the joint. The temptation to attempt to back-off 1 or 2 joints below the identified free point should be firmly resisted.

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FIGURE 1 Straight hole, straight pipe. Stuck in drill collars.

, ,,,,,,,,,,,, ,,,,,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,, ,,,,,, , , , ,,, ,,,,,, , , , , ,, ,,,,,, , , , , , ,,,,,,, ,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,, ,,,,,, , , , ,,,,,,,,,, , , , , ,, ,,,,,, , , , , , , , ,,,,,,,,,,,, ,,,,,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,,,,,,,,, , , , ,,, ,,,,,, , , , , ,, ,,,,,, , , , , , ,,,,,,, ,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,,,,,,,,, , , , ,,, ,,,,,, , , , , ,, ,,,,,, , , , , , ,,,,,,, ,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,,,,,,,,, , , , ,,,,,,,,, ,,,,,,, PIPE SKETCH

DEPTH

PULL & TORQUE % OF FREE PIPE READING 0

10

20

30

40

50

60

70

80

90 100

PULL TORQUE

DRILL PIPE

DRILL COLLARS

BACK-OFF HERE

VERY POOR

POOR

GOOD

BACK-OFF CHANGES 911208/3

Both stretch and torque readings confirm the stuck point is in the same drill collar. Where there is little wall friction, a sharp drop-off in both readings is observed below the free point.

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FIGURE 2 Differentially or stuck by heaving, sloughing formation.

,,,,,,,,,, ,,,, , ,,, , , ,, , , , , , , , , , , , , , , ,,,,, ,,,, , ,,, , , ,, , , , , , , , , , , , , , , ,,,,,,,,,, ,,,, , ,,, , , ,, , , , ,, , , , , , , , , , , ,,,,, ,,,, , ,,, , , ,, , , , ,, , , , , , , , , , , ,,,,, ,,,, , ,,, , , ,, , , , ,,,,,,,

,,,,,,,,,, ,,,, , ,,, , , ,, , , , ,, , , , , , , , , , , ,,,,, ,,,, , ,,, , , ,, , , , ,, , , , , , , , , , , ,,,,, ,,,, , ,,, , , ,, , , , , , , , , , , , , , , ,,,,, ,,,, , ,,, , , ,, , , , , , , , , , ,,,,,,,,,, ,,,, , ,,, , , ,, , , , , , , , , ,,,,,,

PIPE SKETCH

DEPTH

A

, , , , , , , , , , , , , , , ,,,,, , , , , , , , , , , , , , , , , , , ,,,,, , , ,, ,


10

20

30

40

50

60

70

80

90 100

PULL TORQUE

BACK-OFF HERE

B

C

D

VERY POOR

POOR

GOOD


To stretch or torque the pipe becomes more difficult as depth below the free point increases. The FPIT decreases rapidly below collar B, the pipe should be backed-off either at collar A or collar B.

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FIGURE 3 Straight hole, bent pipe.

, ,,,,,,,,,,,, ,,,,,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,, ,,,,,, , , , ,, ,,,,,,, , , , , , ,,,, ,,,,,,,,,,,, ,,,,,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,, ,,,,,, , , , ,, ,,,,,,, , , , , , ,,,,,,, , , , , , , ,,,,, , , , , , , ,,,,,, ,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,, ,,,,,, , , , ,, ,,,,,,, , , , , ,,,,,,,,, , , , , , ,,,,,,, ,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,, ,,,,,, , , , ,, ,,,,,,, , , , , ,,,,,,,,, , , , , , ,,,,,,, ,,,,,, ,,,,, ,,,,,, , ,,,, ,,,,,, , , ,,, ,,,,,, , , , ,,,,,,, ,,,,,,,,,, PIPE SKETCH

DEPTH


10

20

30

40

50

60

70

80

90 100

PULL TORQUE

COLLAR A

BACK-OFF HERE COLLAR B

FREE POINT

COLLAR C

COLLAR D

COLLAR E

VERY POOR

POOR

GOOD


It is difficult to obtain normal torque readings in a badly bent string. Normal stretch and torque for this string are read above collar B. Below collar B, stretch is normal but torque reading is decreasing with increasing depth. Normal torque readings can often be obtained below collar B by applying an overpull on the pipe.

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FIGURE 4 Crooked or deviated holes.

,,,,,,,,,,,, , , , ,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,, , ,,,,,,,,,,,,, , , ,,,,,,,,,,,, , , , ,,,,,,,,,,, , , , , ,,,,,,,,,, , , , , , ,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,, , ,,,,,,,,,,,,, , , ,,,,,,,,,,,, , , , ,,,,,,,,,,, , , , , ,,,,,,,,,, , , , , , ,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,, , ,,,,,,,,,,,,, , , ,,,,,,,,,,,, , , , ,,,,,,,,,,, , , , , ,,,,,,,,,, , , , , , , ,,, ,,,,,,,,,,,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,, , ,,,,,,,,,,,,, , , ,,,,,,,,,,,, , , , ,,,,,,,,,,, , , , , ,,,,,,,,,, , , , , , ,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,, , ,,,,,,,,,,,,, , , ,,,,,,,,,,,, , , , ,,,,,,,,,,, , , , , ,,,,,,,,,, , , , , , ,,,,,,,,,,,,,,,,, ,,,,,,,,,,,,,, , , ,,,,,,, ,,,,, PIPE SKETCH

DEPTH


10

20

30

40

PULL TORQUE

50

60

70

80

90

100

A

B

C

D

E

F

ATTEMPT BACK-OFF HERE

VERY POOR

POOR

GOOD


In deviated wells it is normally possible to transmit torque deeper than stretch. The torque reading is often a function of the pull on pipe. Generally best torque transmission is obtained at relatively low values of pull. Some judgement must be exercised in what can be backed-off. While a back-off may at times be made with less than 25% stretch reading, it is useless to attempt a back-off without a torque reading of at least 50% of free pipe.

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6.

PRE-JOB PLANNING AND GENERAL DISCUSSION ON FREE POINT AND BACK-OFF OPERATIONS

6.1

Rig Floor Safety and Precautions The following equipment should be checked to ensure a safe Rig Floor operation:

6.2

a)

Tong and slip dies. These must be sharp, clean and of the correct size to bite and hold the pipe, kelly or whatever part of the string protrudes above the rotary.

b)

Tong snub lines and jerk lines. When a jerk line must be used to apply left-hand torque instead of a reverse gear on the rotary, be certain that it is in perfect condition and is long enough to allow several wraps on the cathead with plenty of rope remaining to be easily handled. Snub lines on the tongs should be double cables and in good condition.

c)

Slip handles. Tie the slip handles together with a strong piece of soft line. This is done because it is possible for the pipe to break high when back torque is being applied. If this should happen, the pipe may part completely and jump due to the strain. The slips would be thrown clear and become a dangerous projectile.

d)

Block, hook and elevator. When applying torque, the elevators should be latched around the pipe and slacked off below the tool joint, so that the pipe can rotate freely through the elevators. The hook is locked when the pipe is being rotated while sitting on the slips.

e)

Residual torque. Make sure that no residual torque remains in the string of pipe when it is picked up out of the slips, unless it is being held by the tong. If residual torque is present, it will spin out and wrap up the logging line and hoisting equipment.

Running FPI Tools and Interpretation of Collected Data A BHA and drill string diagram is filled in Figure 7, page 20, with all troublesome hole areas highlighted. The driller should be consulted as to the exact time and hole conditions when the string became irretrievably stuck. Highlight the hole geometry, particularly at kick-off depths and to make known the borehole's past and present problem areas.

6.2.1

Produce an assembly drawing with DC numbered.

6.2.2

Make up tabulation as follows:

Time

6.2.3

Conn. No.

Size

Depth

Initial Pull x 1000 (lb)

Final Pull x 1000 (lb)

Meter % Points (Stretch)

RH/LH Turns Put In

Amps

Torque

Meter % Points (Torque)

Always take tension readings prior to torque readings especially in deviated wells. For deviated holes, both stretch and torque readings should be done to determine whether the pipe is free or not.

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6.2.4

The same overpull increment (normally 50,000 lbs) should be used when determining the free point at each reading.

6.2.5

Take two or more readings at the same spot by applying the selected weight increment without slacking off. Each increment may not necessarily give the same reading. In a deviated hole you will get low reading bottom side - good reading centre of hole and decreasing again as string is pulled to top side of hole.

6.2.6

Tension should be worked down the string by applying the surface overpull determined to give the required overpull increment at the tool depth, and then slacking off to the neutral weight at the tool depth. This should be repeated 4 or 5 times, until the FPI gives consistent readings. Make sure that the total overpull applied when taking a reading is well above the string weight.

6.2.7

As can be seen from the "Stretch reading scale" (page 21), the stretch reading is not a linear function of the overpull. This implies that larger overpull increments only give marginal increases in stretch reading. For example: Stretch measure in HWDP at 50 lb/ft with a 50,000 overpull increment gives according to the stretch chart a reading of 80 meter points. This is the case in any weight range, whether it be 100,000 lbs to 150,000 lbs or 300,000 lbs to 350,000 lbs.

6.2.8

If the reading in the above case would actually be only say 65 meter points and one is certain that at this point the string is free, then a line drawn on the chart from 50 lbs/ft pipe weight through 65 meter points gives an actual overpull at this point of 30,000 lbs (refer to page 21). This indicates the importance of taking a calibration reading at a point in the string that is known to be free, in order to get an idea of friction in the hole. Assume now that a stretch reading is taken in the drill collars weighing 150 lbs/ft situated below the HWDP. When a 50,000 lbs increment is applied the actual overpull is 30,000 lbs therefore a reading of 32 meter points can be expected if the string is free. The calibration point should be in the same type of BHA component as that which is stuck - if the type of stuck component is possible to determine.

6.3

Working Torque Downhole

Note: It at all possible rig up wireline tools and explosive charges through top-drive. It is far easier to transmit torque downhole when working pipe with top-drive. 1.

When the FPI tool is in the hole, careful consideration of the transmittal of RH torque will indicate what Martin Decker weight range is the most efficient and how many turns at surface are required to transmit any torque to the connection to be backed off.

2.

In STRAIGHT wells the weight of string to the back-off point can be calculated using various parameters. i.e.

3.

i) ii) iii) iv)

Weight of string in air to back-off connection. Weight of string in mud + 10%. Recorded string weight up less the weight in mud of the pipe to be left in hole. As indicated by the FPI.

When working in left hand torque, the slack-off and pick-up weights should be adjusted to give the best indications that the torque is being transmitted downhole.

Note: If jars still working, do not slack off enough weight to enable the jars to rework. a)

When the top-drive is used to rotate the pipe, careful monitoring of amps versus turns must be done. Bear in mind the large power input of the top drive. Start slowly with 2 LH turns and work the pipe between 20k overpull and actual FPI or calculated MD weight at the neutral point. Monitor the drop-off in top drive motor amps as the torque is worked downhole. If amp drop-off is difficult to achieve, vary the slack-off and pick-up weights to achieve the

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FREE POINT DETERMINATION AND BACK-OFF PROCEDURES quickest response from the amp meter. Patience is required, it can take several hours to work torque down to the free point, especially in deviated wells. Continue rotating the pipe one turn at a time and working the pipe for each turn.

4.

b)

When using the rotary table to rotate the pipe, strict adherence to safety considerations must be done, as outlined in Section 6.1. Initially rotate the string 2 turns to the left. Adjust the tong line on the back-up post to give maximum up and down travel. Have a torque line pull gauge connected to the tong. Hold the torque in the string with the make-up tong and work the string initially as in a) above. Monitor the decrease in line pull ft.lbs and adjust the slackoff and pick-up weights to give the quickest response. Working the string with the Kelly or blocks has the disadvantage that only 4 ft to 5 ft of movement is possible due to the length and travel of the tong line. Again patience is required to complete winding in LH torque. Good results have been achieved in the past after spending up to 2 hours on this operation.

c)

When the back-off charge has been fired, the minimum weight to work in additional LH torque is: i)

The recorded weight down less the weight of string to be left in hole.

ii)

The weight that corresponds to the best torque response.

The amount of reverse torque to be applied depends on the type, size, depth and condition of the pipe and no firm rules can be given, but a general recommendation is as follows: Drill Pipe from: 0' - 4000' (1200m)

- Use 1/4 to 1/2 round per 1000' (300m).

4000' (1220m) - 9000' (2700m) - Use 1/2 to 3/4 round per 1000' (300m). 9000' (2700m) - Plus

- Use 3/4 to 1 round per 1000' (300m).

Max. surface torque to be 80% of DP make-up torque. 5.

When the position of the back-off has been decided, torque up the string to the right and work this torque down. Record the amp reading or torque readings. Never exceed 80% of this figure when giving the string left hand torque.

6.

Apply 2-3 turns of left hand torque, required for the back-off, and lock the rotary. Use a jerk line and the rotary tongs, with tong gauge attached, to pull off the rotary lock and hold. Pick the string off the slips and work the pipe vertically a few times, set pipe back on slips, pull tongs to relock the rotary. If it is felt that the pipe will accept the remaining left hand torque, apply it. If not, then apply half the remaining torque and repeat the above procedure until the required amount of left hand torque is in the pipe. Frequently, if LH torque is applied with the rotary table, the string breaks at an unintended position. In this case, use the rotary to apply the first portion of the left hand torque, and complete the operation, using the rotary tongs.

7.

6.4

Should the pipe back off uphole in casing, it generally does not damage the cable. If, however, the pipe backs off mechanically while cable is in the open hole, the pipe should be lifted up approximately thirty feet and the tool pulled well above this point, before the connection is remade.

Completing the Back-Off The back-off refers to separating the free pipe from the stuck pipe at a threaded connection just above the free point. It is accomplished by placing an explosive charge across this connection by means of a casing collar locator, while reverse or left hand torque is applied. When the charge is fired, the connection "breaks".

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The three requirements for a successful back-off, in order of importance are: 1.

The explosive charge must be large enough to break the connection.

Note: Too high a number of strands can damage the pin and box, thus preventing reconnection of fishing jars. 2.

Sufficient reverse or left hand torque must be applied.

3.

The proper weight condition at the point of back-off must be obtained.

The back-off charge can be run immediately the FPI is pulled. With the potential for premature back-off high up in the string, the charge is often run to ± 3000 ft (900m) above the back-off point whereupon the remainder of the LH torque is applied to the string. In semi-submersible operations, the charge is run 1 joint below the connection to be backed off - this saves time when correlating on depths - less time for heave conditions to deteriorate. After the string shot has been detonated, recover the charge and check for back-off. If the required connection has not backed-off completely at this point, then further LH torque can be applied to fully unscrew the thread as follows: Reset the string weight as required. i)

Apply approximately half of the original amount of left hand torque used to the pipe. While the torque is being applied, the pipe should back off as evidenced by a loss of torque load. If not, release the left hand torque, noting any loss of torque in the process.

ii)

If the torque was lost, repeat the above process until the back-off is complete.

iii) When no torque is lost during the process, the weight is usually not correct. Slowly adjust the weight up or down while checking the tong line. At the correct weight, the torque load will relax. iv) After a total back-off, if desired, check the depth of the parted pipe by pulling the pipe 5 to 10 ft (1.5m to 3m), setting the slips and checking the point of back-off with the collar locator, but in the case of differential sticking, keep pipe moving at all times. 7.

OPERATIONAL PROCEDURE FOR RUNNING FPI TOOLS Complete BHA sheet, Figure 7.

7.1

Lock swivel and blocks.

7.2

If drilling jars are not stuck, uncock same. For the complete operation do not go below slack-off weight required to re-cock jars.

7.3

Complete surface checks on FPI tool outlined in Section 4.

7.4

Run FPI tool into drill pipe. Depending on the installation the tools can be introduced into the drill pipe in several ways as illustrated in Figure 10. a)

Top-drive or Kelly. Remove bull plug on top of gooseneck or remove complete gooseneck/ washpipe assembly.

Note: Install wireline protector into washpipe entry area. If none available, fabricate same. Be extra careful not to drop debris down string!

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If the rig is equipped with long casing links, the cable and IBOP equipment can be rigged up as illustrated in Figure 10.

Note: When running FPI, it is not necessary to compensate the cable for vessel heave. Once the anchoring mechanism has been deployed, the cable is slacked off 10 - 15 feet to compensate for vessel movement. 7.5

If the string is stuck below the jars, calibrate the tool in the collar above jar (Ref. 6.2.8). From the calibration run, if free pipe gives a meter reading of 85%, then an estimation of hole friction can be made. This is important later on in the back-off operation when the neutral weight has to be found for the connection to be backed off.

7.6

Position the FPI tool in mid-joint and deploy the anchoring mechanism. Take stretch readings from neutral weight in area of interest with 50K overpull increments. Continue taking stretch readings and ascertain at what depth stretch is good or bad. To save time, if the jars are free, the first stretch measurement should be taken above and below the top stabiliser.

7.7

When the stretch is deteriorating, take torque readings to confirm stretch. One RH turn per 1000 ft to the point of interest is made. The torque may have to be worked down. With the SIT C and F tools, this is a disadvantage as these tools cannot differentiate between stretch and torque. The following technique can be done to determine whether torque can be transmitted downhole and can be measured by the SIT C and F tools.

7.8

a)

After stretch measurements, with 5-10K overpull on string, set FPI tool in mid joint.

b)

Put all RH turns into pipe.

c)

Set meter on SIT panel to 80 meter points (full scale deflection).

d)

Watch the meter. If the reading decreases, it means the torque is coming out of the pipe, thus torque is being transmitted to that point, i.e. the pipe is free. This is an excellent indicator in gauging how easy or difficult it will be to put LH torque into the string for the back-off.

The neutral weight can be determined with the FPIT before pulling the tool as outlined below. In deviated wells, it is often impossible to calculate the correct weight to pull to ensure neutral weight at the connection to be backed off. Buoyancy, friction in the hole and weight of pipe laying on the low side will have an indeterminate effect upon the calculated and actual Martin Decker pull required. A more accurate method of determining neutral weight in deviated holes is to measure the neutral weight directly with the FPI tool: a)

Instruct the driller to compress the pipe with 50,000 lbs below the estimated neutral weight at the tool depth. (Do not go below weight which will cock jars.)

b)

Set the FPI tool.

c)

Instruct the driller to pick up in 10,000 lbs steps.

d)

Record all FPI readings on the worksheet and plot them out as in Figure 5.

e)

The neutral weight is halfway between the first FPI deflection and the point where the increase becomes clear.

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Curve Becomes Linear

FPI Response

Neutral Point

FPI Reading

FPI Response Begins

Drill Pipe Tension

FIGURE 5

It should, however, be understood that even maximum string tension would result in an overpull at a neutral point that is small in comparison to the parting force produced by a back-off explosion. As a general rule, when attempting to position the neutral point err on the side of overpull rather than compression, thereby limiting the potential for a connection above the required back-off point preferentially parting. By careful observation of the tool readings the free point indicator can indicate pulls and torque required to overcome friction. It is, therefore, essential the Drilling Supervisor is in the logging cabin to record and observe the behaviour of tension and torque indicators. 8.

RUNNING THE BACK-OFF CHARGE See Section 0160/GEN : Use of Explosives in Drilling Operations. With the FPIT, a back-off charge can be run in tandem. However, this is not recommended for the following reasons: a)

6 strand maximum to be run, only good for tubing and 5" drill pipe.

b)

The CCL and FPIT mechanism can get damaged.

c)

If the tool was dressed to anchor inside 5" pipe and this pipe was subsequently found to be free, in order to make measurements inside drill collars, the FPIT has to be pulled from the well to change the arms. A potentially hazardous operation to remove a live charge above the rotary table has now to be carried out.

If a TANDEM FPIT run and back-off charge is required, then the following table of depth versus pipe size can be used:

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Pipe Diameter

Depth

Primer Chord

5" 19.5 lbs/ft 5" HWDP 8" DC

8000' 5000' 3000'

6 strands max. 6 strands max. 6 strands max.

Note: The mechanical arms of the FPIT cannot be deployed prior to firing the back-off charge. The build-up of LH torque can be observed with the FPIT prior to firing the charge. 8.1

Torque up the string fully to the right to the maximum of the drill pipe in use. Work in the RH torque. This may take a considerable time to do properly. Watch the ammeter and the MD weight indicator and observe if torque is being transmitted downhole.

8.2

Arm the back-off charge with primer chord as per Figure 6.

8.3

In floating operations to compensate for vessel heave, when running the back-off charge, an extra long carrier strip of primer chord can be used. This will ensure the explosive force is focussed at the connection. To increase accuracy, the electric line can be partially compensated for vessel heave by rigging up the lower wireline sheave to the stuck pipe as illustrated in Figure 10, page 24. Approximately 80% of vessel heave is accounted for using this rig-up.

8.4

Run below stuck point and tie in with the CCL.

9.

APPLYING LEFT-HAND TORQUE TO CONNECTION TO BE BACKED OUT The 2 most important considerations for a successful back-off as mentioned previously are: a) b)

Correct neutral weight at connection to be backed off; and Sufficient applied LH torque at that connection.

The following technique should be used to transmit torque downhole. See Section 6.3 for top drive or rotary table applications. 9.1

Rotate the string 2-3 turns to the left with 5K overpull at the stuck point. Quickly drop the brake catching the string with the weight on top of the stuck point. It may be necessary to slack off weight to less than the neutral point of the string. This action will initiate the LH torque downhole. Continue working in LH torque more slowly now with 1 turn at a time. (Do not exceed 80% of the make-up torque. This will ensure that a connection further up the string will not back off.) Work the string every turn with 20K overpull and 40K downweight on the stuck point. Hold the torque in the string with a tong line which has a gauge installed. As the string is being worked the gauge will indicate the drop off in surface torque if the torque is being worked downhole. The amount of weight to overpull or slack-off when working the string can only be judged by noting how quickly the torque is going downhole. There are no fixed overpull or slack-off weights to quote in order to best work the torque downhole. Each hole is different and by careful observation of the Martin Decker and tong-line gauges the optimum weights can be found. The string must be worked carefully, it may take several hours to work in the torque to the stuck point. The time taken to do this operation will be more than repaid with a successful back-off.

Note: Do not slack-off enough weight to recock jars. 9.2

With the correct amount of LH torque in the string, set correct neutral weight at joint to be backed out. Careful attention has to be given to selecting the correct weight. Most unsuccessful back-offs are caused by incorrect neutral weight.

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9.3

Position back-off charge against tool joint to be broken out. Note that wireline is not snagged or trapped against derrick structure or in travelling block assembly.

9.4

Check with driller on heave and make an allowance for this. The back-off charge can be made longer to accommodate covering more than the length of the combined tool joints. This will allow a small error in depth due to the vessel's heave. (The length of primer does not affect the explosive strength. The number of strands is the governing factor on the force of the explosion.)

9.5

Fire back-off charges. If the charge has gone off, surface indications include possible loss of CCL circuit and increase in cable tension. The driller should see a reduction in surface torque. The pipe should not spin back at surface as all the torque will be lost downhole if the back-off is successful.

9.6

To confirm joint has backed off at the correct place and if CCL is working, pull cable back to the next connection above back-off point.

9.7

Lift string carefully and check for overpull. If joint has not fully backed out, work string up and downpipe may "pop" out of threads. If unsuccessful, gently turn in a few more LH turns and work string.

9.8

When pipe is free, pull electric cable. Work drill string and if possible circulate through pipe. FIGURE 6 - Primacord Shot Strength

Depth from Surface 0 (feet) to PIPE OD (inches) 3000' Tubing

Drill Pipe

Drill Collar

Casing

3000' to 6000'

6000' to 9000'

9000' to 12000'

Over 12000'

Number of 80 gr/ft RDX primacord strands to be

2-3/8 2-7/8 3-1/2 4 to 4-1/2

1

1

1

2

2

used according to depth

1

1

2

2

3

and pipe size.

2

2

2

3

3

2-3/8 to 2-7/8 3-1/2 to 4 4-1/2 to 6-9/16 6-5/8

1 2 2 3

2 3 3-4 4-5

2-3 3-4 4-6 5-7

3-4 4-6 5-9 6-10

4-6 5-8 6-12 7-14

3-1/2 to 4 4-1/8 to 5-1/2 5-3/4 to 7 7-1/4 to 8-1/2 9-3/4

2-4 2-4 3-6 4-6

2-5 3-6 4-8 5-9 -15

3-7 4-8 5-10 6-12

3-8 4-10 6-12 7-15

4-9 5-12 7-15 8-18

4-1/2 to 5-1/2 6 to 7 7-5/8 8-5/8 9-5/8 10-3/4

3 3 4 5 5 6

3 3 4 5 5 6

3 3 4 5 5 6

3 4 4 5 6 7

3 4 5 5 6 7

Chart

assumes specific gravity mud 1.2 - well full. Where two values are shown, the higher value indicates maximum explosive load which normally will not damage pipes in heavy mud - these high loads are hard on CCL, head and weights.

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DEVIATED HOLE BACK-OFF Example: Beatrice Platform A15 (Slot 13), angle 60°.

Time

Initial Pull x 1000 (lb)

Final Pull x 1000 (lb)

Meter % Points (Stretch)

RH/LH Turns Put In

Amps

Torque

Meter % Points (Torque)

Conn. No.

Size

Depth

9

9 1/2

3992

100 150 200 250

150 200 250 300

0 1 3 4

3 1/4

740

20000

6

8

8

3959

100 150 300 250

150 200 250 300

30 36 34 27

3 1/4

740

20000

24

Back off connection at 3959 ft. Weight for back-off 155,000 lbs. Primacord used = 17 strands. Left hand turns in = 3 1/4. Back-off was successful. 155,000 lbs represents weight of string in mud and blocks and 10,000 lbs overpull.

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FIGURE 7 DEPTH

BEFORE STUCK

HWDP 15 JTS

3225

WT UP

185,000

X/O

3672

ROT WT

135,000

31.05

1 x 8" DC

3675

WT DOWN

100,000

30.10

JARS

3706 3736

BLOCKS KELLY

35,000 15,000

DP-1 DP-2 8" DC 9" DC

62,887 22,350 43,050 63,000

MUD WT BUOYANCY FACT BUOYANCY WT + BLOCK

9.3 PPG 0.857 163,933 198,932

JARS COCK JARS OFF

90,000 200,000

MAX. DEV.

60°

2.32

123.16

6.30

92.52

3.15 30.39 6.80

4 x 8" DC

12 1/4" STAB

3859 3865

3 x 8" DC

X/O 9 1/2" DC STEEL 14 3/4" STAB

29.98

9 1/2" DC STEEL

14.35

SHOCK SUB

30.72

9 1/2" DC STEEL

3959 3962 3992 3999 4029 4043

4074 4080

6.35 9 1/2" MDC 59.59

4110

6.92 35.37 2.30 6.51

9 1/2" MDC TOTCO RING 17 1/2" NM STAB TELECO TOOL PIN-PIN X-OVER 17 1/2" STAB

28.35 8.51 2.30 7.38 5.47 7.85

9 1/2" MDC MONEL PUP STEEL SUB 17 1/2" STAB STEEL PONY 17 1/2" ROLLER REAMER

4140

2179/2

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FIGURE 8

STRETCH CHART FOR STEEL PIPE PIPE BODY WEIGHT LBS / FT

DRILL PIPE - DRILL COLLARS - TUBING - CASING

1

ADDITIONAL PULL LBS

1.5 SIT-D or SIT-F

300,000

2 3 4

100,000 THIS IS WHY 50,000 LBS INCREMENTS ARE USED TO TAKE STRETCH READING

80,000 60,000 50,000

PIPE STRAIN umm = 10 -6 ft ft = 10 -4 mm

SIT METER READING 'STRETCH'

800 600 500 400 300

40,000 30,000

200

100

90 80

20,000

100 80 60 50 40 30

10,000

20

8,000 10 8 6 5 4 3

4,000 3,000

2

2,000

1

8 10

BECAUSE RESPONSE NON LINEAR TOOL CALIBRATION 20 NORMALLY 80

70 60

30

50 40 30 20

6,000 5,000

5 6

15 10 8 6

40 50 60

E.G. H.W.D.P. 50 LBS / FT

80 100

2

D.C. 150 LBS / FT 2

200 300 400

1,000 PIPE STRAIN,

e P = .1133 x 10-5 m / m, ft / ft, OR IN / IN W L

WHERE:

P = ADDITIONAL PULL IN LBS

W = WEIGHT PER LINEAR FOOT OF PIPE BODY, LBS / FT e = ELONGATION / UNIT LENGTH L SPACING BETWEEN CENTRALIZERS SIT-D 1560mm x 6' 3" SIT-F 1525mm = 60" 2179 / 3

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MAKING UP A PRIMACORD BUNDLE ON UNIJET WIRES •

Install Unijet wires 10 ft (3m) long in adaptor head and tape together each six inches.

•

Lay the first primacord strand, which will later be connected to the detonator, along the length of the Unijet wires and hold in place at a few points with a wrap of 3/4" plastic tape.

•

Build up the required number of strands into a neat triangular bundle around the number 1 strand as shown below.

1

1

Attach this strand to blasting cap Make-Up of Primacord on Unijet Wires Keep strands parallel without twisting, staggering the bends at top and bottom. Alternatively, the strands may be out to length and booted with P-33 771 primacord boots at both ends. •

Tape and string tie the bundle at top, bottom and a few intermediate points.

•

Cut primacord at lower end and install a blind boot.

•

Tape the whole bundle once, half lapping the friction tape.

•

Retape over ends, avoiding excessive use of tape which may plug the bit or hinder subsequent descent. String tie ends top and bottom.

If the shot has been prepared and subsequently not run, the primer chord is scrapped and is never run twice. 12.

MAKING UP PRIMACORD BUNDLE ON A SHOT BAR •

Install a 7 ft (typically) long shot bar to the wireline adaptor head.

•

Lay the first primacord strand, which will later be connected to the detonator, along the length of the shot bar. Hold it in place at a few points by a few wraps of plastic tape.

•

Attach the required number of strands around the bar, each additional strand next to the previous strand. If the circumferential area is covered, a new layer should be started.

•

Keep strands parallel without twisting. Bend round or cut the strands to the correct length.

•

Tape and string tie the bundle at top, bottom and a few intermediate points.

•

Attach the detonator cap to the first strand and cover with rubber boot. Tape and tie both ends.

•

Tape the whole bundle once, half lapping the friction tape. String tie at both ends.

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FIGURE 9

1 3/8 " O.D. UNI-SYSTEM BACK-OFF ASSY. DATA SHEET 111/16" ASSY.

1 3/8 " ASSY.

CCL-L

CCL-N

P. 186792 111/16" TO 1 3/8 " ADAPTOR

P. 30487 P. 186470 - 1 3/8 "ADAPTOR (SUPPLIED WITH PIN)

4" APPROX

P. 190048 - ADAPTOR CLAMP

B-73760 PRESSURE TIGHT CAP

4" TO 5" BUNDLE

10" RECOMMENDED

B. 18272 - B. 15810 SCREW & WASHER

PRIMACORD BUNDLE STRING TIE EACH 6"

P-190048 ADAPTOR CLAMP B. 18272 B. 15810 1 3/8 " (REF) P. 186786 BOTTOM NOSE (SUPPLIED WITH PIN)

OPTIONAL WHEN CENTERING NEEDED

2179 / 69

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FIGURE 10

Crown Sheave

STUCK PIPE SUPPORTED BY ELEVATORS FOR FREE POINT MEASUREMENTS

TOP-DRIVE(or KELLY) CONNECTED TO STUCK PIPE FOR BACK-OFF OPERATION : PARTIALLY COMPENSATED

Crown Sheave

Travelling Assy

TOP DRIVE UNIT

Hook

"Bicycle" frame to route cable into APE

Swivel

For Wireline Entry, remove Gooseneck Bullplug, or complete Gooseneck Assembly

Long Links Top Drive Quill Shaft Bell Line Wiper - can hold 2000 psi

Upper IBOP

IBOP

Lower IBOP Saver Sub

Side Entry Sub

Sheave fixed to Stuck Pipe

IBOP Stuck Pipe Elevators Stuck Pipe

Sheave fixed to Drill Floor

Drill Floor

Logging Unit

Dog Collar Clamp Drill Floor

Logging Unit

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FISHING - PROCEDURES AND TOOLS

FISHING (GENERAL) Fishing is an expensive and non productive operation. All progress stops. General Causes:

1. Equipment Failure. 2. Drill string or casing sticking.

1.

2.

Equipment Failure a)

Exceeding equipment strength limits.

b)

Equipment wear.

c)

Cracks, leading to equipment failures and drill string twist offs.

d)

Lack of good maintenance.

Stuck Pipe a)

Caused by squeezing formations due to insufficient mud weight.

b)

Pressure differential sticking due to too high a mud weight causing too much overbalance or pressure differential.

c)

Poor quality mud, because too high a solid content, high gels, too thick a filter cake or other cause.

Equipment failure can be virtually eliminated by a well established maintenance programme. Stuck pipe is a matter of appreciating the danger of incorrect mud weights and inferior quality mud. Stuck pipe problems, caused by differential sticking have been solved very successfully with solvents such as Pipe Lax, Mud Ban and other similar brands or by lowering the mud weight. In case of no success establish as soon as possible the stuck point. Prevention is far cheaper than cure and whatever tool goes down the hole; contractor or rental tools, ensure these have a certificate of their last inspection. Negligence and payment disputes are solved much more readily if regular inspection and reports are available. In any fishing operation considerable attention must be paid to all equipment run in the hole. 1.

Ensure ALL fishing tools used are recorded on a drawing prior to running.

2.

Ensure all Internal Diameters used can pass back off tools.

3.

Where possible fax a drawing of the fish to the Drilling Office.

4.

Accurate depth records are vitally important. Where a twist off has occurred tag the top of fish prior to POH and strap the pipe on the way out.

5.

The condition of all fishing tools, i.e. grapples, overshot bowls, jars, mills etc., must be physically inspected by the BP Drilling Supervisor prior to assembly and making up.

6.

Ensure solvents are on site, e.g. Pipe Lax or Mud Ban to spot around the fish ASAP.

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GENERAL FISHING PRACTICES (Consult 6050/GEN - Jar Placement and Jarring Practices.)

2.1

Fishing Assembly Fishing tool - bumper sub - jar - 1 x DC - stabiliser - accelerator - HWDP - DP.

Note: For the number of DC’s required, see 2.2. Assembly should be chosen according to tool availability and problems encountered for each job at hand. 2.2

The fishing string DC weight should equal or exceed the weight of the fish. It is recognised that in some cases this amount of drill collars may exceed the accelerator’s manufacturers recommendations.

Note: Review the amount of DC’s run with an accelerator to achieve the desired jarring effect, taking into account the deviation of the hole and the possibility of differential sticking. The principle is that the heavier the fishing assembly then the greater the duration of impact. Minimum drill collar weight results in a destructively high impact velocity, striking the jar anvil for a minimal time and inducing an ineffective movement of the fish. The JARPRO PROGRAMME can be consulted on this issue. 2.3

An accelerator is required in deviated holes and when fishing at shallow depths, where there is insufficient pipe stretch to achieve the necessary impact on the fish.

Note: Ensure the accelerator stroke length exceeds that of the jar. 2.4

A bumper sub is required in all fishing assemblies.

2.5

Stabilisers may be incorporated into an assembly to provide stabilisation of the fishing tool. Inside casing a soft blade or non-rotating stabiliser is required.

2.6

Only when using taper taps, die collars or washover strings, should a safety joint and circulation sub be installed in the assembly (to facilitate a circulation and release capability should problems occur).

2.7

A circulation sub is required where tool ID’s are small and/or where there is a possibility of toolstring becoming plugged. Note that excessive jarring may cause the sleeve to shear out and prevent circulation through the fish. Always ensure the shear pins in the sleeve are new.

2.8

Ensure that all fishing equipment is properly maintained and that there is an updated inventory at all times.

2.9

During each fishing operation ensure that there is a good understanding of the fishing tools (their strengths and applied stresses) by ALL drilling personnel. (Communication is vital.)

2.10

Ensure dimensions of all downhole equipment are recorded and a drawing made of each tool prior to running in the hole.

2.11

Ensure all depths and pipe tallies are correct.

2.12

Ensure contractor and rental tools have updated and valid inspection reports available. Ensure all fishing tool ID’s can accommodate any internal fishing or back-off tool which may subsequently be run.

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2.13

The Drilling Superintendent must be informed of any alteration or modification to any standard fishing tool.

2.14

If a twist off occurs, the hole should be circulated and the mud conditioned prior to pulling out of the hole. This is not so necessary if there are few cuttings in the hole (e.g. very slow drilling rates). •

Avoid washing out the hole above the fish.

•

Improve mud properties where possible to assist fishing operations.

•

Tag fish prior to pulling out of hole. Strap pipe during pulling out of the hole.

•

If differentially stuck, lower mud weight or implement “U” tube method (if there are no well control ramifications) only if approved by Drilling Superintendent. Refer to Sections 6000/GEN and 6010/GEN.

•

While pulling out after a twist off, check every connection for washouts.

2.15

With a twisted off string at surface, check the counterpart of the fish CAREFULLY to determine as accurately as possible, size, shape and condition of fish. See item 4.2.2.

2.16

When bit cones or similar junk items have been lost on bottom and it is considered better to fish than to sidetrack around fish, a jet junk retriever is the first option unless an “Apple” tool is available (an “Apple” tool with redress kits should be organised).

2.17

Fax a drawing of the fish to the Drilling Superintendent.

2.18

Prior to connecting to a fish, ensure that the following are known: •

String weight up, down and rotating with and without circulation (as applicable for each tool run).

•

Free rotating torque of the fishing string.

•

Pipe stretch and strokes of fishing tools.

•

Jarring calculations, safe working loads, strengths of fishing tools, etc.

•

Establish circulating rates and pressures.

•

Circulate and condition mud prior to fishing, if required.

2.19

Tools are to be checked by Drilling Supervisor prior to running into the hole.

2.20

Ensure that during the fishing operation, the tool joints of the fishing string are not opposite the BOP’s.

2.21

Circulate slowly when searching for fish. An increase in pressure, while lowering, and/or rotating, will confirm tool location on top of fish (pack-off rubbers normally good for up to 1000 psi). At this point shut pumps down if required. If fish does not come free and back-off is required, refer to Section 6150/GEN.

2.22

When a fish is free, circulate bottoms up before flow checking and pulling out. Check degasser operation.

2.23

When fishing packer/completion assemblies initially circulate over chokes.

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While Pulling Out a Fish: •

Do not pull more than 85% of the minimum yield strength of the pipe.

•

Circulate while working the fish through tight spots.

•

Pick up and set string in slips carefully avoiding any shock loading to toolstring.

•

Do not rotate a fish while pulling out of the hole.

If fishing tools cannot be released, the installation of a surface jar with a 48” stroke will provide the necessary bump down to release the fishing tool. Ensure that the surface jar is initially set on its minimum tonnage adjustment to prevent damage to the surface equipment.

Note: Prior to jarring, ensure that all surface equipment is in a state of readiness. 3.

GENERAL JARRING PRACTICES

3.1

Preparation for Jarring Operations (Consult 6050/GEN for additional information.)

3.2

1)

Check derrick and equipment for loose bolts, clamps, sheaves, etc. before and during extended periods of jarring.

2)

Prior to jarring mark string at the rotary table.

3)

Check drill line sensator thoroughly. Ensure weight readings are correct and that the anchor line clamp remains secure.

4)

Have all unnecessary personnel off the drill floor during jarring operations.

5)

If applicable, installation of the kelly is required before jarring. With top drive regularly check top drive components. Bleed down top drive counterbalance system, if applicable.

6)

If prolonged jarring is expected (e.g. cutting and pulling casings), consider laying out swivel if kelly is in use.

7)

If elevators are used for jarring, ensure latches are additionally secured.

8)

Ensure rig floor supervisors are kept informed of tool use, strengths, capabilities, problems envisaged, etc.

Jarring Operations 1)

Always allow the jars to trip at their safe working load before pulling to the maximum allowable limit. Know safe working loads for all tools. Never exceed this until jar has tripped. Only then apply extra overpull.

2)

When using a surface jar, commence at lightest tonnage setting available, then increase as required.

Caution: Do not set trip tonnage of surface jar greater than the weight of free pipe to surface above the stuck point. This prevents the fish being pulled tighter into the stuck point. 3)

Slip the blockline regularly. Rule of thumb 2 - 4 hours while jarring.

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4)

After fish is recovered, slip and cut blockline at the casing shoe during first trip into the hole.

5)

Depending on the jar in use, maximise the jarring efficiency.

Note: With the pump on: Efficiency is increased when jarring up. Efficiency is decreased when jarring down. 6)

Avoid running jar in the neutral point. This will cause rapid and severe damage to hydraulic mechanisms.

7)

Normally position jars at least 10m from any stabiliser to allow jar to flex.

8)

Ensure that type of jar selected will do the job. Follow manufacturer’s recommended operating procedures.

9)

Ensure operating instructions are available on the rig.

It is essential that all Drillers are fully aware of jar operating techniques and are fully conversant with fishing situation. This relies on good communication. 4.

FISHING EQUIPMENT

4.1

Force Multiplying Tools General The operation of force multiplying tools, i.e. jars, accelerators and bumper subs, primarily exploit the force contained in the stretch of the toolstring. Bumper subs provide a method of delivering upward and downward blows. Jars provide a force for upward and/or downward blows dependent on type of jar in use. Accelerators or jar intensifiers increase the force of these blows by releasing stored energy as the jar trips. The upward movement of the drill collars in the fishing string is accelerated and as the jar reaches its full stroke the total impact is delivered directly to the fish.

4.1.1

Conventional Bumper Subs General A hexagonal, splined or other shaped mandrel and body transmits torque and allows several inches of upward or downward stroke to the fishing string. It also assists in defining the neutral point and allows for string movement for the “working in” of torque. This allowance for movement by a stretched string is adequate to activate the releasing mechanism in overshots and spears. Also generally adequate for freeing a stuck fish or tool in a moderately sticky formation. The bumper sub should be installed immediately above the fishing tool. Operation a)

To “Bump Down” Pick up string enough to open tool completely and take an allowable strain on the string (hole drag plus 20,000 lbs initially). Note free movement while bumper sub is opening.

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By dropping the string to within 6” of the closed position of the tool and stopping the string abruptly with the brake, the lower end of the string will be caused to bump downward, closing the bumper sub. Due to the elasticity of the string, a series of downward blows will be delivered to the tool below the subs. b)

To Bump a Solid Downward Blow Pick up string as above, i.e. length of tool stroke. Drop the string to its neutral weight without braking. The bumper sub will quickly close. The lower end of the mandrel body strikes the shoulder on the lower end of the mandrel, transmitting a single solid blow to the tool below.

c)

To Bump a Solid Blow at Surface in Order to Disengage a Fishing Tool Leave at least 1 DC above bumper sub. Pick up stroke of bumper sub and bump down on fish. A solid blow will occur to the fishing tool effecting release of tool from the fish.

4.1.2

Accelerators General An accelerator concentrates the jarring action within the drill collars above the jar, preventing the “hammer” forces dissipating up the string. This results in a higher hammer velocity which increases impact and impulse. It is a powerful component within the fishing BHA and should always be run. An accelerator is a totally free end consisting of a sliding mandrel within a sleeve. When the drill string is run in the hole, the accelerator is stroked out. When overpull is applied and the jar trips, the accelerator will stroke up and the jar will impact before the accelerator does. For this reason, the stroke of an accelerator MUST be greater than the stroke of the jar. Care must be taken when using a combination of a jar and an accelerator. Very high impact forces are generated and calculation of possible loading must be done prior to deciding how many drill collars to run between the two components. The JARPRO computer programme can be used to determine the loadings on a fishing BHA when using an accelerator.

4.1.3

A fishing assembly of Jar, 4 x DCs, Accelerator, 4 x DCs would be sufficient to jar up successfully and have enough weight available to jar down to free spears, overshots, etc.

4.2

Overshots

4.2.1

General Guidelines and Procedures 1)

A pack-off is required with an overshot in order to circulate through the fish before pulling out. When fishing TCP guns, do not use a pack-off as it would prevent circulation.

2)

Do not limit the penetration of the fish into the overshot to facilitate tool release from the fish. The primary objective is recovery of the fish and the grapple’s taper will allow release with a forceful knock downwards.

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3)

Use an extension sub when appropriate to enable the desired catch area to be reached by the grapple and packer. Ensure that, on full engagement with the fish, both the grapple and the packer element will NOT be positioned alongside any reduced diameter such as a slip or elevator recess.

4)

Try and utilise full strength overshots at all times. (This is the only tool designed to withstand jarring and rotation.)

Note: A slim hole overshot is designed for pick-up only. 5)

A spiral grapple can withstand greater overpulls and has a greater contact area between bowl and fish. However, if the top of fish requires dressing, a basket grapple and mill control are required.

6)

If utilised for a back-off, to prevent backing off top sub or bowl connections, a standard overshot with left handed bowl, guide and top sub connections is preferred.

7)

If utilised for backing off 3 1/2” or smaller tubulars, a standard overshot with right hand threaded bowl tapers and appropriate grapples is preferred. Left hand rotation would normally release tool from fish. However, if slight tension is applied, enough torque can be applied to back off smaller tubulars before tool releases itself.

Note: The make-up torque of tubulars is significantly less than the make-up torque of overshot connections. 8)

Spiral grapples will effectively pack-off a worn fish as much as 3/32” undersize. Overrange of each grapple is approximately 1/32”.

9)

Basket grapple tolerances are the same as for spiral grapples.

10) If size of fish is uncertain, consideration should be given to a multibowl and grapples. 4.2.2

Operational Procedures Surface Checks Check overshot is correctly dressed, that bowl tapers and wickers on the grapple are unworn with all parts in good condition. It is worth testing the grapple on the recovered section of the fish. If the grapple can fit onto the matching part of the fish on surface, it is in fact too big and the next size down should be used. Ensure top sub is bored out (to allow passage of free point indicator and back-off tools) and internally painted. Ensure accurate measurements and drawings have been made and recorded. Select correct guide shoe and mill control to suit situation and hole conditions present. Check that the guide shoe will not pass the fish in the hole. An oversized guide shoe may be required. Once the overshot is made up, ensure that the grapple is free to move in the overshot bowl. Engaging the Fish Prior to engaging the fish, check weights up and down and rotating. Circulate above fish to clean top of fish. Record pump rates and pressures. Tag top of fish to ascertain its exact depth. Circulate bottoms up if you have been out of the hole for an extended period.

Note: If gas has accumulated in the borehole (especially in production wells) and it is not possible to circulate when latched onto the fish, the gas may become a problem when pulling out.

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Pick up string and commence rotating slowly and pumping at a low rate. Lower string slowly until weight is taken and/or a pressure increase is observed. Stop the pump, ensuring that no pressure is trapped. Continue rotating and lower string until sufficient weight has been taken. Stop rotating and release any torque from the toolstring. Pulling on the Fish A pull on the fishing assembly causes the grapple to be moved downwards in relation to the bowl of the overshot resulting in a firm grip on the fish being taken. If the fish does not come free, then attempt to circulate down through the fish. If the fish comes free, continue circulating at least bottoms up. Prior to Pulling Out of Hole If it is uncertain how well the fish is engaged, consideration should be given to carrying out the following procedure as it is better to drop the fish on bottom than POH. With overshot engaged and any torque released from the string, ensure a firm grip on the fish is taken by lowering part of the string weight onto the overshot (+/- 40% of fish string weight). Pick up the fish 2 to 3m and drop the string 1m, catching the string on the brake. Pulling Out of Hole Avoid bumping string when setting the slips. Circulate through tight spots. Do not rotate the fishing string. Releasing the Overshot from the Fish If the fish does not come free, the tool can be released by bumping down on the fish and rotating simultaneously to the right. Picking up on the toolstring will allow the overshot to feed itself off from the fish. Precautions When Using Tools Unless an upward strain is maintained, never rotate the fishing string to the left while the overshot is engaged with the fish. Always bump down the toolstring before starting releasing operations. Increase bump down weight as required if tool cannot be released. Always shut off pumps before lowering overshot over the fish (to prevent damaging seal/packer). When fish has been freed, monitor trip tank levels at all times and circulate at least bottoms up. 5.

SPEARS

5.1

General 1)

Spears should be dressed with a pack-off to circulate through and around the fish.

2)

A stop ring or stop sub should be utilised to prevent too deep an entry into the fish, to provide the ability to reset jars, and to enable easier tool release.

3)

Spears should be run in the latch position.

4)

If release of spear from the fish is required, bump down before commencing releasing operations.

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5)

In order to release the fish, right hand rotation while picking up the string will feed the left hand wickers on the spear slips or grapple off the fish.

6)

On smaller spears, install a circulation sub in the fishing assembly to prevent the small ID from becoming plugged.

7)

If the spear requires rotation to release the slips (e.g. J slot, etc.), in deep or crooked holes more than one full turn to set or release the spear will be required. Always maintain a moderate upward strain on fishing tool when rotating for release or setting operations.

8)

In thin walled tubing or casing, release spear frequently to ensure wall deformation will not prevent tool release.

9)

When engaging spear, space out toolstring so that a tool joint is just above the rotary table.

Operational Procedures Surface Checks Examine and ensure that spear grapple wickers are sharp and the size is correct for the fish to be engaged. Ensure that the spear is correctly assembled and that all parts are in good working order. Ensure all measurements of tools are taken and recorded. Prior to RIH, with the spear made up on the string, check release and operation of grapple on main spear body. Reset spear into latch position for running into the hole. In deep wells the grapple should be secured in the catch position. Drill a small hole in the grapple and spear mandrel, then pin in place with a mild steel pin. Above the Fish Check string weights up, down and rotating, monitor free rotating torque and establish circulating rates and pressures. To Engage and Pull the Fish Tag fish by noting weight decrease or pressure increase. Shut down pump at this point and bleed off any trapped pressure. Lower string until spear has entered fish to the desired depth (measure amount of entry). Prevent stop ring from bottoming out. Rotate spear, if applicable, to rotate mandrel of tool through the grapple, setting the grapple in its engaging position. Fish can now be pulled. Pulling will wedge the grapple into a positive engagement on the fish. When engaged attempt to circulate. If circulation is not possible, maintain up to 1000 psi to enhance jar performance. If pressure can be maintained, jars can be reset without bottoming out on stop ring due to pack-off friction. To Release from the Fish Bump down with the weight of the fishing string. This breaks engagement of spear grapple on the fish. Rotate a few turns to the right and pick up the string until spear is clear of fish. Right hand rotation moves the mandrel up through the grapple forcing the grapple down against the releasing ring and putting the spear in the release position.

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If the spear does not release, bump down, then simultaneously rotate to the right. Pick up the string until spear is clear of fish.

Note: With prolonged jarring operations using a spear, it is essential that at least once every hour the spear is released from the fish then re-engaged. This prevents the possibility of the spear grapple becoming “bedded” into the fish. Consider running a safety joint in the fishing assembly, especially when fishing large diameter casings as the spear grapple can very quickly become irretrievably locked to the fish. 6.

WASHOVER STRINGS

6.1

General Washover strings are required where: 1)

The formation has bridged off and stuck the string.

2)

Where the string has become cemented.

3)

Washing/milling over a stuck completion or drill string BHA.

4)

Dressing the top of a fish to latch onto with a fishing assembly.

5)

Where sidetracking is impossible.

Generally a maximum washover string length of 50m should not be exceeded. This will prevent the wash string from becoming mechanically stuck or from twisting off (especially in deviated or crooked holes). 6.2

Washover Shoe Selection Inside Casing: Hard facing only on the inside of the shoe. In Open Hole: Hard facing can be both inside and outside. Clearance is small; use a thin walled shoe. Free movement and torque observation is critical in such operations. Due to temperatures required for proper application of cutting materials, it is best to maintain 3/8” minimum wall thickness in the dressed or head area of the shoe. This ensures adequate strength to prevent tearing and allows the wall thickness to hold enough cutting material to accomplish washover and milling operations. To allow adequate circulation and to reduce torque, adequate clearance is desirable on the ID and OD of the shoe. It is recommended that the ID of the cutting head of the shoe be dressed to at least 1/16” less than the wash pipe ID and the OD to at least 1/16” larger than the wash pipe OD. This permits the use of inner and outer gauge cutters on the head of the shoe which will trim the fish so it passes on to the wash pipe without interference. The outer gauge cutters provide a circulation path in the annulus for cuttings removal. Where conditions allow, these clearances should be enlarged, provided that the 3/8” minimum thickness of the shoe can be maintained.

6.3

Washover Operations 1)

Washover shoe selection is critical for a successful operation.

2)

The number of washover joints to be made up will be dependent on: a)

Length of pack-off to stuck point.

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b)

Hole conditions and tolerances.

c)

Generally no more than 30m should be initially run.

3)

A safety joint, drive sub, bumper sub, jar and drill collars should be installed above the washover string. Install a junk basket into the assembly if required.

4)

The assembly is run into just above the fish. At this position:

5)

a)

Establish string weights, string stretch and rotating weight.

b)

Carefully note free rotating torque at various RPM’s between 20 and 100.

c)

Establish various circulation rates and pressures.

a)

Start rotating slowly with low RPM (20 - 50).

b)

Slowly lower the string until light weight is taken (6,000 lbs maximum).

Note: Utilising low weight and RPM initially will reduce the possibility of splitting or flaring the washover shoe. c)

Monitor torque continuously as progress is made.

d)

Use sufficient pump rate to remove cuttings. Monitor mud properties and confirm at bottoms up that cuttings are being returned.

e)

Once progress is being made, establish weight, torque and RPM to achieve the optimum ROP. RPM Weight

20 - 100 max. 2,000 - 8,000 lbs max.

Note: a) Rotation and circulation should be stopped periodically. b) Torque build-up and string resistance should be monitored continuously.

7.

f)

It may be necessary to pump viscous pills to assist in removing cuttings from the annulus.

g)

Regularly pick up the wash shoe. This will maximise wear and effectiveness of shoe.

h)

Once operation is complete, the hole should be circulated clean, the wash string removed and the fishing assembly made up.

i)

An overshot assembly will generally be run.

j)

Attempts will be made to circulate through and retrieve the fish.

k)

If fishing is not successful, then a free point indicator tool and back-off will be required.

l)

Once the back-off is achieved, the washover operation is repeated. This is repeated until all of the fish is retrieved.

JUNK SUBS AND JUNK BASKETS Junk subs and junk baskets are used for removing objects generally too heavy to be removed from the hole by normal circulation. They are run as close to the bottom of a BHA as possible.

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Junk Subs 1)

Up to three junk subs may be run in tandem for excessive junk removal.

2)

In completion fluids the assistance of viscous pills will generally be required to lift junk off bottom.

3)

General procedure would be to go to bottom at maximum pump rate and work junk sub on/off bottom a few times. If a bit/mill is used, spudding and rotating to break up junk would not be uncommon. The pump would be shut down for a few minutes periodically just off bottom. The procedure is repeated until all of the junk is recovered.

Operation The mud stream agitates the junk and lifts it. The annular capacity between the wall of the tool and the hole is smaller towards the bottom of the sub. Above the basket the annular capacity is greater resulting in a lower flowrate. Junk drops out of the mud at this point into the junk basket cup. The junk is retrieved when the basket is pulled.

7.3

7.4

Operational Procedures a)

Rotate to bottom at maximum pump rate.

b)

Gently tag bottom, pick up 6” and fish for junk. This will lift and remove any small, light pieces of junk which would otherwise be further jammed/pushed into the hole if weight on bit was applied. After fishing for junk, sit on bottom and rotate noting torque.

c)

Stop the pump and work the string slowly +/- 10m.

d)

Repeat a) to c) until on bottom torque is smooth.

Jet Junk Retrievers The jet junk retriever should always be stored completely undressed, i.e. with the finger cage, bearing races and shear pin assemblies removed. Store these in oil or grease. Check free rotation of cage within bearing races once the tool is dressed and made up to the string. After the tool is made up to toolstring, ensure fingers are free. Do not install nozzle protectors as they could jam in place. Run retriever in the hole at a controlled rate to within a few metres of bottom. In open hole and if formations are loose or unconsolidated, break circulation regularly to flush the basket. On bottom establish weights, circulation rates/pressures and free rotating torque. Rotate slowly and tag fish. Clean top of fish and circulate as required.

Note: Take care fish does not damage internal fingers while rotating to bottom. When the retriever and top of the fish is clear, drop the ball and slowly pump the ball to seat. Allow up to 2 min./300m for the ball to seat. When the ball seats and the piston shear pins shear, pressure may increase or decrease dependent on tool size. (The flow area of the flushing nozzle may be more or less than that of the jet nozzles.) When pins shear, run the pumps at normal operating rates. Rotate down to the fish, and work the string to retrieve junk into the tool.

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“Core Type” Reverse Circulating Junk Retrievers

Note: Coring should only be considered where very soft formation enables coring with minimal rotation. 1)

Ensure correct size of ball is available before the tool is run.

2)

Check all ID’s of the string to ensure that the ball will pass.

3)

Ensure catcher fingers can rotate and work freely after the tool has been fully made up.

4)

Run the tool to above the fish.

5)

Slowly pump the ball to seat while working the string just above the fish.

6)

Once the ball is seated increase circulation rate and rotate the string slowly while lowering the basket to the bottom of the hole.

7)

In soft formations continue rotating until a core of at least 0.25m has been cut. Core with 2000 - 5000 lbs, and 20 - 100 RPM. Feed drum constantly when coring.

8) 7.6

Increasing torque may indicate that the tool is passing over or encountering junk on the bottom of the hole.

Hydraulic Junk Retrievers (“Apple” Tool) Prior to running this tool, the profile of the previous bit should be considered. A bit with a concave head will leave a raised profile in the centre of the hole. This raised section tends to make the soft fingers of the “Apple” tool deform. When the tool is lifted off bottom, this deformation can cause any captured junk to fall out. Check at surface that the tool is correctly assembled. a) b) c) d) e) f) g)

Back-off tool and remove outer barrel and shoe. Remove piston and check “O” rings on inner barrel. Install finger sleeve on piston (grub screws). Re-install piston back to upset on inner barrel. Make up outer barrel and mill shoe using chain tongs. Check rupture disc is in place and drop ball is retained. Check ball will pass all ID’s of the fishing string.

Run in hole with the tool. Install kelly or top drive prior to tagging fish. Engage pump and establish operating parameters. Wash down to top of fish. Max. 350 GPM for 16 1/2”, 11 3/4” and 8 1/2” tools. Max. 200 GPM for 5 3/4” tool. Tag fish or bottom with minimal weight. Circulate and condition mud if required. Apply light weight and low RPM to work junk inside the tool. 2000 - 5000 lbs, 20 - 100 RPM.

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(Cores may be cut if required. Fingers will cut soft to medium formations.) Release the ball, and pump slowly to seat. (+/- 1 1/2 - 2 minutes per 300m.) If hole conditions permit, stop rotating prior to ball seating. A pressure increase will be observed as the ball seats. The piston will close with a stall pressure of less than 2500 psi. When the piston has closed the tool, the rupture disc in the top sub will shear at 2500 psi and circulation can be continued. Raise the tool off bottom before recommencing rotation. Keep circulation to a minimum once the tool is closed.

Note: If considerable time is lost breaking off the kelly to drop the ball, it may be necessary to work back over the junk with the pump off to avoid operating the tool prematurely. 8.

TAPER TAPS AND DIE COLLARS Taper taps and die collars should only be run as a last resort. The disadvantages associated with them outweigh the advantages.

8.1

Operational Procedures Both tools are run in the hole to the top of the fish. Circulation is commenced and the string rotated. As light a weight as possible is then applied and the tapered threads of the tool cut and embed the tool on/in the fish.

8.2

Advantages of Taper Taps and Die Collars Simple and easy to run. Inexpensive and no maintenance required. After running tools with no success, the fish OD or ID may have been dressed or distorted sufficiently to use another type of fishing tool.

8.3

Disadvantages of Taper Taps and Die Collars Tools cannot be released once engaged. A safety joint, circulation sub and jarring assembly should be run in conjunction with these tools. Fish engagement may be difficult to achieve. Tools have a limited catch range. Connections in most cases only withstand limited overpulls or jarring capabilities. Gauging of torque is very difficult to monitor during operations. The ability to apply limited torque can result in an insecure hold. If too much torque is applied, the tool can become damaged or the fish can become distorted, making further engagement impossible. With taper taps, string shots and cutting tools cannot be run due to the restricted ID’s of the tools.

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9.

MISCELLANEOUS FISHING TOOLS

9.1

Wireline Spear A wireline spear to run to fish for parted wireline downhole. The tool should be run in to a maximum depth of 150m or until resistance is encountered. The spear is then picked up every 10m until resistance is encountered. The tool is rotated one or two turns ONLY. When engaged an overpull is taken until the line and equipment come free or the line breaks at its weak point.

Note: Install an open circulating sub above the rope spear. A stop ring is required to prevent the spear from passing too far past the wire and possibly getting further stuck. 9.2

Impression Blocks Run the tool to above the top of the fish. Circulate above the fish to clear the fish and increase the accuracy of impression. Lower the LIB (Lead Impression Block) onto the fish and apply weight as required. Pull the tool out of the hole and examine impression.

Note: If required, place an open circulating sub above the LIB. 9.3

Fishing Magnets There are two basic types of fishing magnet: a) b)

Permanent magnets. Electro-magnets.

Type a) is supplied by fishing companies and type b) by wireline companies. a)

Permanent Magnets The properties of two common magnets are stated below: Bowen Fishing Magnet Material: Alnico Suitable for temperatures up to 550°C This type of magnet does not deteriorate in storage. However, in service whilst making and breaking contact between magnet and ferrous material the magnet demagnetises. Red Baron Fishing Magnet Material: Samarium Cobalt Suitable for temperatures up to 250°C This magnet will suffer reversible losses with increasing temperature, of the order of 0.28%/deg C up to 250 deg C. When cooled, the magnet will recover its magnetism. The common forms of reduction of magnetism are:

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FISHING - PROCEDURES AND TOOLS Air Gap The smallest irregularity in the mating surfaces between the magnet and item being lifted will seriously reduce the effective weight being lifted and holding force available. These air gaps can be produced by paint or plating on the surface of the ferrous material on which the magnet has been placed, or by roughness of the mating surface. A gap of as little as 0.5 mm reduces the pull by 70%. In order to reduce the risk of deterioration of the magnet when in storage, a cover plate should be installed.

2)

Temperature Magnetism decreases with increasing temperature.

Recommended Running Procedure RIH to just above the fish. Break circulation to disturb the junk on bottom. Cease circulation and tag fish without pumping. Pick up and shear out circulating sub. Pump slug and POH. Advantages of Permanent Magnets a)

Can be run on drillpipe and can utilise the circulation holes in the magnet to eliminate settling of material above the fish or to loosen the fish. To be effective, the magnet must touch the fish.

Note: Consideration should be given to placing an open circulating sub directly above the magnet to assist in circulating the fish clean. Disadvantages a)

They cannot be flown by helicopter.

b)

They cannot be turned off when running in hole and may collect iron fillings which prevent a positive contact with the fish.

Note: Refer to Bowen charts prior to selecting a magnet. b)

Electro-Magnets As with permanent magnets, the lifting capacity of the tool is dependent on the contact area between the fish and the tool and bottom hole temperature (the lifting capacity of the magnet decreases with increasing temperature). Advantages of Electro-Magnets a)

They can be transported by helicopter.

b)

They can be turned on or off so that they do not collect metal filings that could prevent a positive contact with the fish.

c)

They can be run with a casing collar locator for precise location.

d)

They can be run with other wireline tools.

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Disadvantages a)

It is not possible to circulate whilst on bottom. This could have major implications if attempting to fish in an “old” well that has a lot of small iron filings on bottom around the fish. The magnet may pick up the small particles preferentially, preventing the fish itself from being picked up.

The specifications for the Schlumberger and Western Atlas tools are shown below. Halliburton Logging do not possess an electro-magnet, but do run the Schlumberger and Atlas tools. Schlumberger claim that the magnetic field of the CERT tool is momentarily interrupted as the tool contacts the fish. A “spike” appears on the current meter and the field current can be monitored all the way out of the hole to confirm that the fish is still attached to the magnet. Atlas Wireline Services supply both 4.5” OD and 6.75” OD tools, with the following specifications: OD Length Weight Max. Voltage Max. Amp Max. Lifting Power Pressure Rating Temperature

4.5” 14.00” 55 lbs 35 V 2.0 A 575 lbs 15,000 psi 400°F

6.75” 17.20” 100 lbs 55 V 1.5 A 1680 lbs 15,000 psi 400°F

The maximum lifting power quoted above is based on 100% contact of a 2.0” thick slab. The lifting power will decrease according to the amount of contact established with the fish. Bottom hole temperature will have some effect on lifting power, but this has never been a problem in previous fishing jobs. Schlumberger supply a 5” OD tool, with the following specifications: Flat Plate Lift Capacity in Air 1,000 lb Maximum Temperature 350°F Maximum Pressure 20,000 psi Tool OD 5 in Tool Length 27 in Tool Weight 97 lb Guide Shoes available for 7, 7 5/8” and 9 5/8” casing of any weight. Minimum residual magnetic field after degausing. 9.4

Tubing Cutters These may be chemical or explosive cutters and are used if tubing or packers do not come free after pulling with the maximum allowable pull. When the packer is pulled free, circulate bottoms up over the choke. While pulling out the tubing string, circulate while working the fish past and through tight spots. Ensure that the rotary bushings are locked at all times.

9.5

Tubular Perforating (Collars, Drill Pipe & Tubing) Introduction Following a stuck pipe incident on Bruce Well 9/9a-A07(D4), perforating guns were run to gain circulation by perforating through the 8" drill collars using 2 1/8" silver jet charges. Two unsuccessful attempts were made even though there was a positive indication of the guns firing. This was due to sloughing of sediment above the original free point. Further the guns themselves became stuck leaving

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the adaptor, gun strip and bull plug downhole. The string was finally severed using a JRC severance charge. Following the perforating failures, work was initiated to demonstrate the suitability of charges, reasons for the guns becoming stuck and make recommendations to prevent re-occurrence in future. The work was further expended to address all perforating for drill collars, drill pipe and tubing using either Atlas or Schlumberger. Recommendations 2 1/8" Enerjets or Silverjets should be run to perforate 8" DC. Use a Fin type bull plug and not full diameter one to allow passage of charge debris. The number of shots required will depend on the TFA necessary to achieve the desired circulation rate. To reduce the risk of charge debris wedging the toolstring, especially inside a drill collar, the minimum shot density should be used (ideally 1 spf). However, to avoid excessive gun lengths, generally it will be necessary to increase shot density above 1 spf to provide adequate flow area. Run the following toolstring: Fin type plug, 2-3 ft of 2-4 spf strip guns (Silverjets or Enerjets), a magnetic positioning device to hold the shots against the tubular wall, a CCl, plus sufficient tool weight. Position the gun carrier to give maximum charge clearance such that the back of the charge is against the inside diameter of the pipe to be perforated (as shown below). This configuration is less likely to result in bending of the carrier strip on firing.

WRONG

Drill collar

CORRECT

CHARGE

Carrier strip

DIRECTION OF FIRE

DIRECTION OF FIRE

Pressure should not be applied while the charges are being fired as this may result in charge debris plugging the newly formed perforations. A pack-off and pumping sub will be required at surface to allow circulation to be established after perforating. Recommended perforating charges and hole diameters by Atlas and Schlumberger for perforating drill collars, drill pipe and tubing are summarised in Table 9.5.1.

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TABLE 9.5.1 Recommended Perforation Charges from Atlas and Schlumberger for Perforating Drill Collars, Drill Pipe and Tubing Average Exit Hole Diameter (in)

Schlumberger Charge

Average Exit Hole Diameter (in)

Tubular

OD

ID

Atlas Charge

Drill Collar

10 9 8 6.75 4.75

3 - 3.75 2.5 - 3.75 2.25 - 3.75 2.25 - 3.25 1.75 - 2.81

2 1/8 SJ 2 1/8 SJ 2 1/8 SJ 2 1/8 SJ 1 11/16 SJ

0.37 0.37 0.37 0.37 0.32

2 1/8 EJ 2 1/8 EJ 2 1/8 EJ 2 1/8 EJ 1 11/16 EJ

0.34 0.34 0.34 0.34 0.32

Drill Pipe

6.625 5.00 3.5 2.375

5.965 4.0 - 4.41 2.6 - 2.99 1.82 - 1.99

2 1/8 JJ or SJ 2 1/8 JJ or SJ 2 1/8 JJ or SJ 1 11/16 JJ *

0.26 - 0.37 0.26 - 0.37 0.26 - 0.37 0.24 - 0.32

TP Brown TP BR or GR TP BR or GR TP YEL

0.34 0.22 - 0.34 0.24 - 0.34 0.35

Tubing

7 5 4.5 3.5 2.375

5.92 - 6.54 4.0 - 4.56 3.24 - 4.09 2.44 - 3.07 1.70 - 2.04

2 1/8 JJ or SJ 2 1/8 JJ or SJ 2 1/8 JJ or SJ 2 1/8 JJ or SJ 1 11/16 JJ *

0.26 - 0.37 0.26 - 0.37 0.26 - 0.37 0.26 - 0.37 0.24

TP BR or GR TP BR or GR TP BR or GR TP BR or GR TP YEL

0.23 - 0.34 0.23 - 0.34 0.22 - 0.34 0.23 - 0.34 0.25 - 0.37

Schlumberger:

EJ TP

Mneumonics for Charges: Atlas:

JJ SJ

Jumbo Jet Silver Jet

Enerjet Tubing Puncher Brown, Green or Yellow Charges

* The clearances are small, therefore there is a greater chance of the gun sticking.

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FISHING TOOL CHECK LIST The following “first phase” fishing tools should be on site and in good condition.

Note: Ensure that all fishing tools stipulated in contracts on contractor rigs are on site and in good condition. 1.

Overshots and oversized guides with grapples, baskets and extension subs to catch all sizes of tools in the hole.

2.

Fishing jars to match the DC string in use.

3.

Bumper subs to match the fishing jar in use.

4.

Junk Mills with 1/8” gauge tolerance for 12 1/4”, 8 1/2” and 6” holes.

5.

Jar accelerator to match hydraulic jar in use.

6.

Reverse or straight circulating baskets for hole size required. (Use jet reversing type as first choice.)

7.

Junk subs for required hole size.

8.

Casing spears when running casing, complete with stop rings and pack off assemblies for required casing weights.

9.

Fishing tools to catch electric logging tools (to be supplied by logging company).

10. Safety joints and circulating subs. 11. Taper taps and die collars (optional). 12. A hard formation bit, Security H7T or equivalent for 12 1/4”, 8 1/2” and 6” holes. 13. Solvents, e.g. Pipe Lax, Mud Ban, etc. in sufficient quantity for the hole section being drilled.

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STUCK LOGGING TOOLS

If during logging in the open hole, tool sticking occurs, there are two possibilities: the tool itself or the cable is stuck. In either case, the sticking may be due to several different downhole conditions; differential sticking, keyseating in a dog-leg etc. Before rigging up: Check that logging fishing tools are available. 1.

GENERAL POINTS

1.1

ALWAYS make repeat section below the casing shoe.

1.2

KNOW the maximum safe pull you can apply BEFORE the tool gets stuck and the size of the cable.

1.3

NEVER pull more than 9000 lbs on a cable. (2500 lbs on 3/16” cable - breaking strength is 5100 lbs).

1.4

NEVER pull more than 7500 lbs on a spliced cable.

1.5

NEVER pull more than 4500 lbs on the standard weak-points unless you intend to break it, and never try to break it except on orders from Shore Base. (Normal safe pull for small cable is 1125+ (depth x .80) lbs in order not to break weak point which is 1500 lbs).

N.B.

Cut-and-thread is obligatory for tools with radio-active sources.

1.6

When calculating the surface tension to apply 4500 lbs to the weak point, REMEMBER to allow for the weight of the tool in mud.

1.7

In DEVIATED HOLES, use the “cat-head effect” chart to calculate pull at the weak point.

2.

TOOL STUCK ON BOTTOM

2.1

Pull to maximum safe tension and hold it. Close tool.

3.

TOOL STUCK DURING LOGGING

3.1

Close tool, try to go down. If tool is free to descend, make several attempts to pass bridge.

3.2

If tool is not free to descend, either tool or cable are stuck. Pull maximum safe tension and hold it.

3.3

If a CST gun becomes differentially stuck, it may be possible to free the tool by firing the guns, whilst holding maximum tension on the cable.

4.

If the tool fails to come free after the above have been attempted, stripping over should normally be commenced. On no account attempt to break the weak point unless permission has been given from base. If stripping over, proceed as follows:

4.1

Apply the last known “up logging” tension to the cable. For floating installations remove the compensator and apply this tension over a five minute period. (Position the cable so that the maximum heave coincides with this tension.)

4.2

Land cable and cut above rotary table.

4.3

Connect spear head to the hole end of the cable and a spear head overshot to the unit end.

4.4

Strip over the wire with Bowen overshot and drillpipe, stand by stand, maintaining the minimum logging tension plus 500 - 1000 lbs. In deviated wells, occasionally pull the maximum logging tension as this

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STUCK LOGGING TOOLS

ensures no slack wire is being pushed ahead of the grapple or is bird nesting inside the drillpipe above the grapple. 4.5

Prior to latching the fish, a circulating sub and a special bushing to catch the cable are installed, and the cable landed in it.

4.6

Install the kelly/top drive and circulate to clean overshot and fish prior to latching. After circulating, remove kelly/top drive, connect spear head overshot to spear head. Apply the tension determined in 4.4.

4.7

Lower string and engage the fish. A tension increase when lowering, or tension increase when pulling the string upwards indicates the fish is connected. A tension decrease while pulling upwards can indicate that the fish is latched. Similar indications can indicate that the line is caught in the overshot (formation, wire damage, attitude of the wireline in the wall of the open hole section). If these signs occur and the overshot is not in the vicinity of the fish, install the circulating sub and circulate in an attempt to clear the overshot (move the pipe until the above tension returns).

4.8

After latching onto the fish, part the cable with the travelling block, remove the spearhead overshot combination, connect the cable together and wind in. Pull the string and recover the fish (see Section 8).

Note: While running in the overshot a decrease in cable tension may occur indicating that the tool has come free. In this case the cable is connected and the tool pulled up until the overshot latches onto the fishing head. The procedure is then as before. 5.

RECOVERING STUCK TOOL BY BREAKING WEAK POINT If hole is in reasonable condition or in casing, a tool can be fished out with good probability using the technique of breaking the weak point and fishing with an overshot with OD slightly smaller than bit size. To avoid the risk of breaking the cable, unintentionally, never pull more than 9000 lbs on unspliced cable. Do not use this technique for tools with radioactive sources (refer to Section 8).

6.

NEVER, NEVER suddenly release tension on a cable. This causes “bird- cages” and broken cables. Tension should be released slowly and should never drop below 1/2 the “normal” logging tension.

7.

The Logging Engineer will always direct the operation when applying and releasing tension on the cable.

8.

FISHING FOR RADIOACTIVE LOGGING TOOLS If a radioactive logging tool sticks in the hole, the following procedure should be adhered to: a)

Ensure that the weak point will not be broken. Do not continue endlessly to “work” the tool since this may reduce the weak point.

b)

Inform base and provide all relevant information - position of fish, allowable tension of weak point and cable, etc.

c)

Base will then decide on further action.

d)

Ensure that the Logging Engineer informs his Shore Base representative.

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STUCK LOGGING TOOLS

Note: All work performed with radio-active sources will be conducted in accordance with the Ionising Radiations Regulations 1985, No. 1333, and the rules of the logging contractor. 8.1

Fishing Operations Regardless of where the fish is stuck the cable will always be cut and threaded through the drillpipe (see section 4). Ensure the following points are adhered to: a)

Circulate once around prior to latching on to the fish.

b)

Monitor constantly the mud returns with a Gamma Ray tool placed in the return line or close thereafter. If an increase in radiation is detected, then no personnel are to be near mud pits or return lines other than the logging contractor.

c)

Do not locate or engage tool with more than 10,000 lbs weight.

d)

Discuss with base maximum allowable pull.

e)

Ensure that with the tool engaged in the overshot, circulation remains possible. Use a circulating sub in the fishing assembly one stand above the overshot.

f)

When the fish has been latched do NOT part the cable at the weak point. Recover the tool by retaining tension on the cable. This will necessitate cutting the cable on each stand pulled.

If the above procedures fail to recover the tool and it is important that it be recovered, a separate programme will be issued. 8.2

Handling of Retrieved Source The following points should be adhered to:

8.3

a)

Limit rig personnel to the minimum required on the rig floor.

b)

Pull the source as far as possible in the derrick (minimum 50 ft).

c)

Cover rotary table, close rams, etc. All rig personnel except Driller to leave the Rig Floor.

d)

Driller assists Wireline Contractor in laying down equipment.

Abandonment of a Source in the Hole If all else fails, and a Source has to be abandoned, a separate programme will be issued.

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PACKER MILLING AND RETRIEVAL

PREPARATION a)

Install a ditch magnet in shaker header box to monitor any excess steel cuttings.

b)

Run the torque and drag simulation to confirm the packer can be milled on rotary and determine whether or not lo-friction casing protectors are required and their placement. If this is not possible, fit casing protectors to string, particularly over well build-up/drop-off sections. Check protectors to ensure they are not worn and pins are secure, any protectors that drop off on top of the packer will have to be fished.

Note: Special protectors and depth limitations are in effect for hot wells - e.g. Clyde platform. c)

Install a drillpipe wiper over the hole when RIH and POOH. This prevents debris from dropping on top of the packer.

d)

In highly deviated wells where high torque values have been experienced or are indicated by torque drag simulation, consideration should be given to using a mud motor to drive the milling assembly or to replacing the wellbore fluid to oil mud. As the pilot mill is likely to back off due to the whip when it breaks free, a special trip should be made to fish the packer after milling.

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MAKING UP PACKER PICKER ASSEMBLY AND CHECKING EQUIPMENT a)

Space Out of Packer Picker

Packer Mill

C

Mandrel (may add extension subs if required)

Packer Latcher Engages Here B

A

Catcher Mechanism

Mill-out Extension

Clean-out Entry Mill

Seal Bore Protector

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Dimension B must not exceed dimension A (the mill out extension length). Even if the small cleanout mill is smaller than the seal-bore protector ID, the chance should not be taken to include this mill passing into the seal-bore protector as junk or debris during the milling operation may get trapped inside the tailpipe and be trapped at this reduction in ID between mill-out-extension and the seal-bore protector. Thus the packer picker will be able to mill the complete packer length dimension C before the small clean-out mill has reached the end of the mill-out extension. b)

Standard assembly is packer picker c/w correct length of spaceout mandrel, three junk subs, soft blade or non-rotating stabiliser and circulating sub (refer to page 6 for an illustration of a typical packer picking/milling assembly). This complete assembly is made up on the catwalk, saving time on the rig floor. A home-made assembly to clamp the small clean-out entry mill is placed into the 4 rotary bushing pins and the assembly torqued up.

Note: A sketch of the home-made bit breaker is included on page 8. c)

Check the shear pin nut has been fitted with all the shear pins, each shear pin has a shear rating of 12,000 lbs. Always fit maximum number of shear pins - for 9 5/8” tool 10, and 7” tool 8. Thus to shear assembly off from packer, requires 120,000 lbs and 96,000 lbs overpull for 9 5/8” and 7” packers respectively.

d)

Check catcher mechanism is free to move up against the spring and that the spring is not cracked or damaged. The spring holding ring is checked for tightness.

Note: Recovery should preferably be with a releasable collett type latch mechanism for which a mill-out extension is required in the packer assembly.

3.

e)

The finger catch mechanism should be taped up completely with string parcel tape - this prevents any small pieces of junk or debris jamming between the slots of the fingers and possibly preventing the catching mechanism from operating properly. It has been seen before that small pieces of junk which have caught between the slots have bent the fingers inwards making catching of the packer impossible. The tape also prevents any debris entering the slots when the assembly is run.

f)

A 4- bladed main packer mill should always be used if a choice is available. These mills should always be used when milling full bore permanent packers, as when using skirt type mill (burning shoes) problems may occur circulating junk above the mill due to the restricted flow area.

OPERATING PARAMETERS AND GENERAL NOTES ON MILLING PACKER RIH assembly and HWDP - circulate through assembly 2 - 3 minutes to check small holes in mills are not blocked. Run assembly into 30' above top packer. Include enough drillpipe in a 3 1/2"/5" string to enable the packer to be chased to bottom if the packer cannot be recovered or the sump is considered deep enough to leave the packer and tailpipe on bottom. Establish the up, down and rotating weights. Circulate through assembly at 250 gpm. If using top drive, stab into packer with slow circ. and no rotation. Continue lowering string until main mill has bottomed out on top of the packer. Pick up 30,000 lbs overpull to establish mill is on correct depth and catcher mechanism is operating correctly. If no overpull is obtained, it may be due to: a)

Catcher mechanism not working; or more likely

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Junk or debris is preventing the small clean-out entry mill from passing through the packer and into the mill-out extension.

If (b) is suspected, the mill should be slowly and carefully rotated with minimum WOB to clean out the packer and mill out extension internal diameter. If no or little progress is made, the junk subs should be worked for 5 minutes and consideration taken to pump a high viscous pill round to flush out the debris. If the kelly is being used, the packer should be tagged with no less than 10' useable kelly left - if 10' or less kelly is left, a 10' pup joint should be added to the string and further tagging operations carried out. Care must be taken to determine where the pup joint is in relation to the BOP rams. Once the packer is tagged and the catcher checked with overpull, the milling operation can commence. Mill 9 5/8" packers with 15,000 WOB, increase WOB initially quickly up to 15,000 WOB with 80-90 rpm, 250 gpm. Mark pipe to monitor ROP and every 30 minutes pick string up and work junk subs. Depending on progress pump 20 bbls hi-vis pill every 30-40 minutes to assist in lifting milled cuttings away from top packer. Initially 10 - 12,000 WOB for 7" packers, 80-90 rpm, 250 gpm. The torque pattern should be a steady fluctuating torque indicating that the mill is indeed milling and not spinning on top of junk.

The practice of picking up the string every so often to check that the catcher is still operating or to attempt to pull the packer free should be strongly resisted. This only damages the catcher by forcing junk between the slots or prematurely pulling the packer free when the bottom slips are only partially milled. This causes severe problems when pulling the packer free between casing collars. There seems to be no golden rules for operating parameters to achieve rapid milling speeds. A 9 5/8" packer can be milled in 1 to 4 hours and a 7" packer milled in 30 minutes to 3 hours. After 1 1/2 hours milling, if progress is slow or has stopped, maximum weight should be applied for 9 5/8" packers, 25 30,000 lbs and 7" packers 20 - 25,000 WOB. Enough drill collars should be included in the string for this eventuality. 4.

PULLING OUT OF HOLE WITH PACKER AND TAILPIPE AND BREAKING OUT FISH Once the packer has been milled and an increase in weight is noted, a flowcheck should be made. Circulate well clean as oil/gas may have been trapped underneath. When pulling the fish from the hole, overpull will be experienced at every casing collar connection, particularly in 9 5/8" casing. The string should be carefully worked past the tight spot which is caused by milled junk catching in the ID of the collar and between the milled packer mandrel. The kelly or top drive should be installed to help flush the debris above the assembly. Overpull should be restricted to maximum 30,000 lbs. Time and patience are required - there is no reason to lose a packer when pulling it out. The wear bushing should be loosened in the wellhead when retrieving 9 5/8" packers to prevent the sharp leading edge of the milled packer catching the underside of the wear bushing. If this happens, the wear bushing is simply pulled up the riser by the packer and presents no problems. To break out the packer/tailpipe from the packer picker, the easiest and safest method is to pull the millout extension above the rotary table, set it in the slips and clamp a dog collar around the OD. The connection immediately above the mill-out extension is broken. This allows the milled packer and the packer picker assembly to be lifted off the string. The extension mandrel (if fitted) or the connection above the catcher and spring assembly can be broken in the mousehole - the milled packer removed and then screwed back onto the mill-out extension. The tailpipe can then be handled conventionally.

Note: It is now becoming common practice to Bakerlok this connection - thus the one below should be broken, i.e. between the mill-out extension and the seal bore protector.

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NO RECOVERY If the packer is not recovered, a fishing assembly with a packer picker catcher with a spear above can be run to engage the fish. This gives a double option - again consideration should be given whether or not to run the catcher and spear combination. If debris has fallen inside the fish, it may be impossible to get the catcher into the neck of the packer and preference to run the spear alone may be the best option. Include a bumper sub, jar and accelerator in the assembly.

6.

FISH STUCK WHEN TRIPPING OUT If the packer and tailpipe get stuck when POOH and all options have been tried to release the packer from the obstruction, it will be necessary to shear off from the packer by applying enough overpull to shear the pins on the shear out assembly and POOH with the packer picker. Consideration should then be to run a flat bottomed mill and mill/force the fish to bottom. A standard fishing assembly with bumper sub, jar, accelerator can then be run to retrieve the fish.

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Packer Picker Assy

Lower part of Packer left after milling operation

Break this connection - between Packer & Mill Out Extension

Dog Collar

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PACKER MILLING AND RETRIEVAL 85 - 47 + 38 SABL - 3 RETRIEVING BHA

A

B

C

3.75" OD D

E

A : X/OVER 3 1/2 IF BOX x 3 1/2 REG PIN B : 4 1/2 " TUBING SPEAR C : SPEAR DRESSED WITH 3.902 CATCH D : X/OVER 2 7/8 REG BOX x 2 3/8 REG PIN E : STANDARD RED BARRON CATCH SLEEVE ( 3.875 CATCH ) F : STANDARD NOSE MILL

F 2179/67

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PACKER PICKER CLEAN-OUT MILL BREAKER SUITABLE FOR 9 5 /8 " & SMALLER SIZES

6" OD pipe welded to plate 6" Minimum 1" thick plate Solid bar pins welded to plate Fits into Rotary Drive Holes on Rotary Table

Tong Dies welded inside 6" pipe (3 off) 9 5/8 " Packer Picker Guide/Clean Out Mill Fits snugly inside. For the smaller 7" Packer Picker Assembly, to secure the smaller mill extra tong dies are supplied in between the welded dies.

Lifting Handles

2179 / 68


SUBJECT: 1.


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CASING MILLING

INTRODUCTION Casing Milling is the term given to milling substantial, long sections of casing, following retrieval of the uncemented casing string above. This has been performed typically on platform wells, where the existing well has been abandoned, across the reservoir. The remaining portion of the well has been utilised to allow a new well to be drilled when no further slots have been available on the platform. Long sections of cemented casing have been successfully milled on Magnus (1990) and Clyde (1990 and 1991): Magnus Well M17 (C5) Clyde Well A16Z (25) Clyde Well A22 (19)

580 ft of 9 5/8" 47 lb/ft casing 1726 ft of 13 3/8" 72 lb/ft casing 909 ft of 9 5/8" 47 lb/ft casing

Lessons learnt and techniques developed during these operations have been recorded for future reference. Optimum overall progress relies on both good downhole milling mechanics (mill cutting characteristics, BHA, operating parameters) and the efficient removal of the milled steel cuttings, or swarf. Either aspect may prove the factor which effectively limits the net rate of progress. The bulk volume of steel produced in milling is substantial. The effectiveness of the operation depends to a large extent on how this material is handled on surface. Prior to commencement of milling operations, appropriate preparations in a number of areas need to be considered to ensure that the swarf is removed from the milling fluid and disposed of as efficiently as possible. The swarf produced by milling at rates of 20 ft/hr has been effectively handled for several hours without interruptions, however well designed surface facilities are essential to sustain such progress. The likelihood and probable severity of hole cleaning problems or of blockages on surface must increase at higher milling rates. The most cost-effective rate lies somewhere between the maximum rate at which steel could be cut and a rate at which progress is virtually continuous. Dayrates and the cost/contribution of surface modifications must be included in the assessment. 2.

SELECTION OF CASING MILLING INTERVAL Once the approximate position of the interval has been determined, a number of points should be considered in determining the exact interval. 1.

Well status prior to casing milling operations. Consult cement bond logs to assess the degree of casing-cement bonding over the casing section to be milled. Mechanical performance will be improved across well cemented intervals where lateral play is minimised.

2.

Consult casing string tally to establish position of casing collars and casing jewellry. The section to be milled should start either 5 ft above or 15 ft below a casing collar to avoid the casing backing off from the coupling. Plan to mill as few casing collars as possible and finish the milling above a coupling. Couplings typically contain 80 - 120% more steel per unit length than casing and will rapidly wear cutting blades.

3.

Avoid having to mill centralisers if possible. If this is unavoidable, plan to mill the centralisers at the beginning of the section before the blades are dulled. The potential for tool damage is increased by the lack of restraint on centraliser and stop collars being able to spin around the casing. Also they tend to break into larger pieces and can be difficult to remove.

4.

Establish contents of annulus fluid and consider relevant mud weights for section previously drilled, along with pore pressure, formation integrity and possible zones for potential communication.


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5.

Consider effect of annulus fluids in contaminating selected milling fluids and required steps to be taken.

6.

The ability to effectively rotate the string and apply milling torque should be assessed by reference to the drilling simulator programme (input milling fluid, drillstring and well trajectory data). The high frictional forces in deep or highly deviated wells may dictate the use of well lubricated oil muds.

3.

SWARF REMOVAL AND HANDLING

3.1

Ideally the majority of the swarf circulated from the well will be removed in a gumbo box arrangement situated close to the bell nipple. However, as this facility will not be available in most cases, the routing through the primary solids control equipment will be crucial, especially the elimination of undesirable swarf traps.

3.2

All internal restrictions and instrumentation, metering devices, etc. should be removed from the flowline. Sections with potential for swarf build-up and blockage may need to be temporarily substituted with open trough sections. Suitable access points for rodding the flowline in order to disturb blockages should be provided. Facility to jet the flowline may be useful - temporary connection from header box jetting line?

3.3

Returns should be directed to feed into the top of shaker header boxes, i.e. "top-dumped". If practical, the lower regions of the box should be plated off so that the swarf "flows" with the mud to the shakers and does not build up in the sump. Do not seal off the sump completely as draining through the dump valve may be necessary at some stage.

3.4

The arrangement for managing flow to the shakers may need attention. Thule shakers have gates which lift up to open a slot and perforated guide plates, both features tend to trap swarf and cause it to build up. If not cleared then minor collections of swarf can become major accumulations quite quickly. A weir arrangement is recommended in place of the gates and the perforations should be covered with thin steel plate.

3.5

Swarf will tend to bind in the mesh of coarse shaker screens. The finest mesh sizes robust enough to withstand the duty should be established quickly. It should be practical to use 40 or 60 mesh screens on the top and 80 or 100 mesh on the bottom.

3.6

If the cuttings disposal chute is relatively straight, has a large bore and a convenient intersection point, it may be a practical means of transporting swarf away from the shakers. However, be cautious: a blocked chute can be difficult to clear. A means of getting the swarf from the chute and into skips, and for the regular changing of skips must be devised. A builder's rubbish chute (plastic sections wired together, say 14" minimum ID) is a good means of getting the collected swarf into skips placed on a lower deck.

3.7

SAFETY NOTE: Metal swarf from casing/tubing milling operations on a well which may have produced even low levels of H2S, may contain Iron Sulphide scale. When such scale is allowed to dry and react with oxygen in the air, a chemical reaction takes place where the Iron Sulphide is converted to Iron Oxide (common rust), and H2S will be released. The reaction is exothermic, i.e. heat will be generated. In the presence of other flammable material (including gas which has not been fully purged), a more dangerous situation may develop. Measures must be in place to ensure that such swarf and/or joints of casing and tubing is either immersed in water (to prevent the oxygenation of the scale, and must therefore be kept wet thereafter), or stored in a safe location and allowed to dry completely. As the material (whether fully dried, or immersed in water) is still classified (UN-2793) under the UK Carriage of Dangerous Goods Regulations, the back-load manifest MUST be accompanied by a Dangerous Goods Declaration. Arrangements for the safe onshore disposal of the material must also be in place.


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Paragraph 4.5 of BP HSE Practice 10 (Hydrogen Sulphide) contains further details of pyrophoric scale. 3.8

As a guide to the number of skips required, allow 5 - 6,000 lbs of in situ casing steel per skip (e.g. 106 127 feet of 47 ppf 9 5/8" casing). The bulk volume will vary with the form of swarf cut, a skip may be physically full before the allowable load is reached. Weigh a 3/4 full skip on the crane to test the actual situation. Obviously sufficient skips will be required to complete the job or sustain operations until the next scheduled arrival of a supply vessel. As a minimum, maintain sufficient skips on board to sustain 4 days milling.

3.9

Grating filters or traps should be placed over drains in the vicinity of the shakers to prevent swarf entering and blocking the lines. Simple steel baskets with grating/mesh panels should be fabricated for installation in the mud return lines immediately downstream of the shakers and in the pit room to strain the flow for small pieces of steel. Ditch magnets should also be positioned in both locations, in pairs. If the facility is available, then mud pump suction strainers should be used - sized for the largest tolerable drop in delivery charge pressure. Strainers and magnets must be checked and cleaned frequently by organising a planned cleaning schedule.

3.10

Milling of long sections of casing results in large transfers of heat energy into the milling fluid - high temperatures can be expected (e.g. 180 deg.F while milling at 5600' tvd (Clyde 1991)). Efficient fume extraction and ventilation in the shaker/header box area is required if tolerable working conditions are to be maintained. Examine the practicality of improving the natural ventilation by installing louvres or temporarily opening up sections of walls.

3.11

Small rakes with round-ended tines assist in moving swarf off the shaker screens. Shovels and potato digging forks will be required for manual handling of swarf.

3.12

Cleaning points should be established at locations where swarf can build up and where mud spillages may occur.

3.13

The wear bushing profile should present a smooth bore through the wellhead to avoid any tendency for swarf to become trapped and build up.

3.14

Unnecessarily functioning BOPs or circulating through additional equipment and valves should be avoided in order to minimise potential damage by swarf to seals and seal areas.

3.15

In the interests of subsequent equipment and drilling fluid maintenance, it is important that all remaining pieces of milled swarf be removed from the surface facilities on completion of operations. The mud pumps, lines and valves should be fully inspected. In addition to mud lines and pits, this should include the drip tray, trip tank, areas around and under the shakers and places forming natural traps. BOP ram cavities, kill and choke lines, standpipe and choke manifolds should be flushed.

4.

HOLE CLEANING/FLUIDS Successful milling depends upon the swarf being efficiently removed from the well. The procedures adopted must ensure that the formation of birds nests is avoided. The most important criteria for hole cleaning above all others is the annular velocity. At this time, there are no full guidelines available on pump rates, hole inclination and mill rates as there are for drilling. However, individual cases can be addressed. THE DRILLING PROGRAMME MUST STATE THE MINIMUM FLOWRATE TO BE USED. It should also be noted that at this time the flowrates will be tentative as the simulator used to develop the recommendation is working outside its original design specifications.


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The milling assembly must be designed to minimise pressure loss. Design must centre on maximising flowrate. By way of example only, the following illustrations of recent milling operations are given:

4.1

Operation

Casing Size

Behind Casing

Drillpipe

Deviation Deg.

Flowrate gpm

Window

9 5/8"

Cemented 12 1/4" OH

5"

50/60

520

Slot Recovery

13 3/8"

20" Casing Uncemented

5"

8/18

1350/1450

Slot Recovery

9 5/8"

12 1/4" OH

5"

59

750

Mud System - Selection of Mud Type The selection of mud type must take account of the following criteria: Surface handling system for swarf removal (personnel contact). Downhole torque (check drillstring simulator). Material behind the casing to be milled (requirement for shale inhibition). Logistics. a)

Oil Based/Water Based Mud In general, it is recommended that water based fluids are used. During the milling operation, a high degree of personnel contact with the fluid will be unavoidable in clearing birds nests, collecting and disposing of the swarf. Even with the appropriate protective clothing, use of an oil based mud will inevitably result in increased levels of skin complaints. Additionally, there is an increased risk of environmental pollution when milling with oil based mud.

b)

Water Based Mud Types If a water based fluid is used, then consideration must be given to possible shale inhibition requirements if the operation will expose water sensitive formations. In general, if the formation was previously drilled with oil based mud, a non-inhibitive water based mud can be used as the near wellbore formation will be oil saturated. If the formation was previously drilled with an inhibited water based mud, then an inhibitive milling fluid will be required. There are several types of water based milling fluid that can be used. These include: Bentonite/XC Polymer Bentonite/Sodium Bicarbonate Bentonite/Mixed Metal Hydroxide These are basic systems with no shale inhibition properties. Details on the fluids can be found in Sections 4100/GEN onwards of this manual. If shale inhibition properties are required, specific advice should be sought.

4.2

Mud Properties a)

Mud Weight When possible an unweighted system should be applied if a water based mud is in use as this will greatly assist logistics. When milling casing across open hole, the mud weight should be that as used to initially drill the section.


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Rheology The most important characteristics of the fluid from a swarf lifting consideration is its low shear rate rheology. This defines the viscosity of the fluid at the shear rate it experiences in the annulus. This is best expressed as the yield stress of the fluid, defined as: (2 x 3 rpm reading) - (1 x 6 rpm reading) The following rheological criteria are given as a guideline: PV cP < 10 YP lbs/100 sq ft 50-70 Gels lbs/100 sq ft 35 - 50 Note: With oil based mud, it will be impossible to achieve the low plastic viscosity criteria.

4.3

Mud Contamination Mud contamination by cement from behind the casing may require substantial additions of Sodium Bicarbonate to treat the presence of excess Ca ions. A large quantity of sodium bicarbonate should be available offshore as a contingency if required. Consideration to pre-treating the milling fluid prior to commencement of the milling may also be required. Should oil base fluids be behind the casing, the expected volumes, treatment and disposal, and containment will need addressing.

5.

MILLING ASSEMBLY High steel cutting rates and long mill life cannot be achieved unless the casing mill runs smoothly, good stabilisation is essential.

5.1

The following assembly has proved very successful in milling 9 5/8" casing (908 ft milled in 59 rotating hrs, blades 40% worn): 8 1/2" Taper Mill - 8 1/2" Near Bit Stab - 8 1/2" String Stab - XO - 10 3/4" Casing Mill - 10 3/4" String Stab - 3 * 8" DC - Jars - 8" DC - XO - 9 * HWDP.

5.2

The components of the pilot assembly (below the mill) should be the same size as the casing drift size. The OD of the casing mill (Barracuda/Piranha etc.) blades should be slightly larger (up to 1/4" greater) than the casing couplings. The stabiliser above the casing mill should have the same OD as the dressed mill blades. Stabiliser blades should have an open spiral design to allow cut swarf to pass freely. Sharp lead-ins at the start of the blades should be avoided. Limit the number of drill collars to that required to provide the maximum weight of mill planned.


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There is a real danger of the connections below the casing mill backing out with consequent loss of all or part of the pilot assembly. It appears that some of the steel cuttings do fall downhole and can form a bridge. This could result in having to fish a lost assembly in order to allow access for the next milling assembly. Use "lock-up type" connections if available for the pilot assembly, otherwise connections should be made up "dry", use of a threadlocking compound should also be considered. Since the crossover below the casing mill is obviously a point of stress concentration and hence is the most susceptible to backing out, it is worth giving thought to having the string stab - xo - casing mill section of the assembly made up onshore and shipped out as a unit. Loss of the pilot assembly will cause the mill to wobble or run rough; indicated by uneven drillstring behaviour, erratic torque and reduced rate of progress. The blades become worn in a tapered fashion as the tool is not centralised on the casing stump.

6.

OPERATING PROCEDURES As with any downhole tools, ensure that all lengths and dimensions have been measured before the assembly is run. Also confirm that suitable fishing tools are available.

6.1

Space out the string, if necessary, so that no connection is required during the initial stages of the operation.

6.2

Lower the assembly to about 5 feet above the top of the casing. It is advisable to record all available information to assist in evaluation of the situation if downhole complications develop - check static and rotating hole drags and the free rotating torque. Record pump pressure at the planned operating flowrate and also at a reduced rate (say 50%).

6.3

If it is necessary to tag the casing, be sure whether it is the taper mill or the casing mill which is taking weight. Enter the casing with the pilot assembly - it may be necessary to work the taper mill for a short time to establish clear access.

6.4

Start rotation at a moderate rate (say 120 rpm) with the casing mill blades above the top of the casing and slowly run down to touch it with minimum weight. Regard milling as a machining type operation; allow the mill to cut its profile before increasing rotary speed and weight. Continue at a moderate milling speed (up to 6 ft/hr, say) for some time to establish that the milled cuttings and swarf are being removed from the hole in appropriate volumes.

6.5

The best rotary speed and weight have to be determined for each job, experiment systematically to find the parameters which result in smooth running and a good rate of progress. Normally a rotary speed of up to 190 rpm and 4 - 8,000 lbs WOB will be effective.

6.6

Feeding the drilling line by allowing the drawworks to creep evenly while maintaining a steady weight should be the objective, do not allow the weight to drill-off.

6.7

Increase milling rates only when satisfied that the hole is being cleaned effectively and that the volume of swarf can be handled on surface.

6.8

Unless there is evidence that hard cement is taking a significant portion of the load, then the milling weight would not be expected to exceed 10,000 lbs (less for K55 grade material). Slower rotary speeds should prolong the life of the mill when cutting P110 or harder grades of steel.


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6.9

Mark the pipe at the rotary table in 1' intervals and record casing milling data on a proforma sheet for each increment as the job progresses. Refer to Appendix A at end of section.

6.10

Increases in pump pressure are the first indicator of a hole cleaning problem, swarf will aggregate and pack-off the annulus in a downhole "birds nest". Reductions in swarf volume at the shakers suggest a near surface accumulation or blockage.

6.11

Pump pressure increases may be small (less than 50 psi) or so large that the pumps have to be slowed or even stopped. Cease milling and work the string to attempt to clear the birds nest. If the nest is in the riser, a means of disturbing it is to pull back far enough so that a stabiliser can be made up into the string and then worked down to the wellhead. If a top drive is used, then a stand with a stabiliser at the bottom should be racked back to save time in picking it up.

6.12

Removal of a nest around the drillstring at the bell nipple will require some form of grab or a barbed rope spear to be available for running on a drillfloor tugger.

6.13

Pumping a hi-vis pill after each casing coupling has been milled is recommended. If the flowline is prone to blockage, then it may be advisable to stop milling and flush or rod it periodically before it blocks completely.

6.14

Casing couplings will mill more slowly and may require reduced rotary speed or greater weight. Most non-integral couplings are not threaded to the very end, as a result the unthreaded portion breaks free as the mill blades approach the lower end of the coupling. The loose ring may break up or become trapped and milled, however it may also start to spin on the top of the remaining casing at any stage, preventing the mill from biting. If this occurs then gentle spudding on the ring should cause it to break up or become distorted and trapped so that it can be milled up. Stop rings and centralisers can cause a similar result and should be treated accordingly.

6.15

If drillstring is bouncing or rough running starts to occur, then the weight and rotary speed should be reduced for a while before attempting to gradually increase the parameters again.

6.16

Poorly cemented casing may necessitate lower rotary speeds with less applied weight.

6.17

Milling through badly damaged casing may be problematical and should be avoided if possible. If unavoidable, then swedging and/or internal dressing may be required to prepare the casing prior to milling. Tearing or splitting of severely corroded casing should be minimised by high speeds and light weights.

6.18

On completion of milling, a flat-bottomed junk mill assembly should be run to clean up any debris remaining above the casing stump. Milling of 13 3/8" casing may result in leaving of a cement sheath from the former annulus. It may be necessary to remove this sheath after each mill run to minimise the risk of blocks collapsing in on the BHA. The relatively thin sheath around 9 5/8" casing is unlikely to be self-supporting and should be less of a problem.

WELL NUMBER:

SHOE DEPTH (FT):

MILL TYPES:

MILL RUN NO.

MILL SER. DEPTH IN NO. (FT)

DEPTH OUT TOTAL (FT) FOOTAGE

ROT. TIME (HRS)

OPERATOR:

TOTAL TIME (HRS)

ROTATING ROP (FT/HR)

CUTTINGS DESC.

UK Operations

Rev.

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:

:

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CUTTINGS - A TYPICAL DESCRIPTION IS 80% < 2" LONG.

WEAR (%)

8 of 8

TOTAL TIME - INCLUDES BOTH MILLING AND CIRCULATING, BUT NOT TRIP.

FLOWRATE

:

ROTATING TIME - REPRESENTS THE ON BOTTOM MILLING TIME.

TORQUE FT/LBS

Page

WHERE THE MILLING PARAMETERS VARY SIGNIFICANTLY OVER THE RUN, THE RUN NO. SHOULD BE SPLIT UP TO INDICATE THESE VARIATIONS, e.g. 3A, 3B.

AVERAGE RPM


MILL RUN NO. -

AV. WOM 1,000 LBS

APPENDIX A

GUIDANCE NOTES

NET ROP (FT/HR)

C.S.G. SIZE/WEIGHT/GRADE:

CASING MILLING

DATE JOB STARTED:

BP EXPLORATION

SUBJECT:

CASING MILLING OPERATIONS SUMMARY SHEET


BP EXPLORATION

SUBJECT: 1.

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SECTION MILLING

INTRODUCTION Section Milling is the term given to removing a section of casing, usually cemented, without disturbing the casing string above in "cutting a window". The window can then be used as an exit point to allow a new hole section to be drilled by kicking off through the window. The tools used are commonly known as "section mills" although they are also used effectively in cutting casing strings prior to retrieval. Section milling operations have been successfully performed on Clyde during 1991: Well A22/19 Well A16Y(25)

- 125 ft of 13 3/8" 72 lb/ft N80 at 22° deviation - 80 ft of 9 5/8" 53.5 lb/ft N80 at 63° deviation

Lessons learnt and techniques developed during these operations have been recorded for future reference. Optimum progress relies on good downhole milling mechanics (mill cutting characteristics, BHA, operating parameters) and the efficient removal of the milled steel cuttings, or swarf. The cutting of a window will produce substantial volumes of swarf, the removal of which will require planning to ensure efficient hole cleaning and effective collection and disposal on surface. Section mills are less robust and have much less cutting structure than casing mills; steel cutting rates will be lower and run lengths very much shorter. However, the form of swarf cut may be finer, less spiralled, and consequently less prone to tangling. These factors are influences in the selection of milling fluids and in determining the extent of modifications justified in surface handling facilities. Although the emphasis may be less critical than for casing milling, the principles remain valid and proper planning should not be overlooked. 2.

SELECTION OF WINDOW INTERVAL Once the approximate position of the window has been determined, a number of points should be considered in determining the exact interval. 1.

Well status prior to section milling operations. Consult cement bond logs to assess the degree of casing-cement bonding over the casing section to be milled. Mechanical performance will be improved across well cemented intervals where lateral play is minimised.

2.

Consult casing string tally to establish position of casing collars and casing jewellry. The section to be milled should start either 5 ft above or 15 ft below a casing collar to avoid the casing backing off from the coupling. Plan to mill as few casing collars as possible and finish the window above a coupling. Couplings typically contain 80 - 120% more steel per unit length than casing and will rapidly wear cutting knives.

3.

Avoid having to mill centralisers if possible. If this is unavoidable, plan to mill the centralisers at the beginning of the section before the knives are dulled. The potential for tool damage is increased by the lack of restraint on centraliser and stop collars being able to spin around the casing. Also they tend to break into larger pieces and can be difficult to remove.

4.

Establish contents of annulus fluid and consider relevant mud weights for section previously drilled, along with pore pressure, formation integrity and possible zones for potential communication.

5.

Consider effect of annulus fluids in contaminating selected milling fluids and required steps to be taken.


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The ability to effectively rotate the string and apply milling torque should be assessed by reference to the drilling simulator programme (input milling fluid, drillstring and well trajectory data). The high frictional forces in deep or highly deviated wells may dictate the use of well lubricated oil muds.

SECTION MILLS - TOOL OPERATION A typical section mill tool is shown opposite along with its basic design and operating principles. Tungsten carbide coated knives are hinge-pinned to the tool and are hydraulically actuated to make contact with, and abrade, the casing wall. Depending on its size and design, the section mill generally has 3 or 6 knives. The basic operating principle is similar to that of underreamers. A downward force is created by the pressure drop in the circulating fluid as it flows through an interval nozzle or orifice. The force acts upon a simple piston/cam arrangement to open out the knives until they are wedged into contact with the casing wall. The maximum cutting circle diameter is fixed by selecting knives of the required length or by setting a stop to limit the opening travel of the knives. Once opened, most tools allow a portion of the fluid flow to bypass the nozzle or even directly onto the face of the knives. The consequent reduction in pressure drop is a positive surface indication that the initial cut of the casing has been completed.

4.

SWARF REMOVAL AND HANDLING

4.1

Ideally the majority of the swarf circulated from the well will be removed in a gumbo box arrangement situated close to the bell nipple. However, as this facility will not be available in most cases, the routing through the primary solids control equipment will be crucial, especially the elimination of undesirable swarf traps.

4.2

All internal restrictions and instrumentation, metering devices, etc. should be removed from the flowline. Sections with potential for swarf build-up and blockage may need to be temporarily substituted with open trough sections. Suitable access points for rodding the flowline in order to disturb blockages should be provided. Facility to jet the flowline may be useful - temporary connection from header box jetting line?

4.3

Returns should be directed to feed into the top of shaker header boxes, i.e. "top-dumped". If practical, the lower regions of the box should be plated off so that the swarf "flows" with the mud to the shakers and does not build up in the sump. Do not seal off the sump completely as draining through the dump valve may be necessary at some stage.

4.4

The arrangement for managing flow to the shakers may need attention. Thule shakers have gates which lift up to open a slot and perforated guide plates, both features tend to trap swarf and cause it to build up. If not cleared then minor collections of swarf can become major accumulations quite quickly. A weir arrangement is recommended in place of the gates and the perforations should be covered with thin steel plate.

4.5

Swarf will tend to bind in the mesh of coarse shaker screens. The finest mesh sizes robust enough to withstand the duty should be established quickly. It should be practical to use 40 or 60 mesh screens on the top and 80 or 100 mesh on the bottom.

4.6

If the cuttings disposal chute is relatively straight, has a large bore and a convenient intersection point, it may be a practical means of transporting swarf away from the shakers. However, be cautious: a blocked chute can be difficult to clear. A means of getting the swarf from the chute and into skips, and


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for the regular changing of skips must be devised. A builder's rubbish chute (plastic sections wired together, say 14" minimum ID) is a good means of getting the collected swarf into skips placed on a lower deck. 4.7

SAFETY NOTE: Metal swarf from casing/tubing milling operations on a well which may have produced even low levels of H2S, may contain Iron Sulphide scale. When such scale is allowed to dry and react with oxygen in the air, a chemical reaction takes place where the Iron Sulphide is converted to Iron Oxide (common rust), and H2S will be released. The reaction is exothermic, i.e. heat will be generated. In the presence of other flammable material (including gas which has not been fully purged), a more dangerous situation may develop. Measures must be in place to ensure that such swarf and/or joints of casing and tubing is either immersed in water (to prevent the oxygenation of the scale, and must therefore be kept wet thereafter), or stored in a safe location and allowed to dry completely. As the material (whether fully dried, or immersed in water) is still classified (UN-2793) under the UK Carriage of Dangerous Goods Regulations, the back-load manifest MUST be accompanied by a Dangerous Goods Declaration. Arrangements for the safe onshore disposal of the material must also be in place. Paragraph 4.5 of BP HSE Practice 10 (Hydrogen Sulphide) contains further details of pyrophoric scale.

4.8

As a guide to the number of skips required, allow 5 - 6,000 lbs of in situ casing steel per skip (e.g. 106 127 feet of 47 ppf 9 5/8" casing). The bulk volume will vary with the form of swarf cut, a skip may be physically full before the allowable load is reached. Weigh a 3/4 full skip on the crane to test the actual situation. Obviously sufficient skips will be required to complete the job or sustain operations until the next scheduled arrival of a supply vessel. As a minimum, maintain sufficient skips on board to sustain 4 days milling.

4.9

Grating filters or traps should be placed over drains in the vicinity of the shakers to prevent swarf entering and blocking the lines. Simple steel baskets with grating/mesh panels should be fabricated for installation in the mud return lines immediately downstream of the shakers and in the pit room to strain the flow for small pieces of steel. Ditch magnets should also be positioned in both locations, in pairs. If the facility is available, then mud pump suction strainers should be used - sized for the largest tolerable drop in delivery charge pressure. Strainers and magnets must be checked and cleaned frequently by organising a planned cleaning schedule.

4.10

Milling of long sections of casing results in large transfers of heat energy into the milling fluid - high temperatures can be expected (e.g. 180 deg.F while milling at 5600' tvd (Clyde 1991)). Efficient fume extraction and ventilation in the shaker/header box area is required if tolerable working conditions are to be maintained. Examine the practicality of improving the natural ventilation by installing louvres or temporarily opening up sections of walls.

4.11

Small rakes with round-ended tines assist in moving swarf off the shaker screens. Shovels and potato digging forks will be required for manual handling of swarf.

4.12

Cleaning points should be established at appropriate locations where swarf can build up and where mud spillages may occur.

4.13

The wear bushing profile should present a smooth bore through the wellhead to avoid any tendency for swarf to become trapped and build up.

4.14

Unnecessarily functioning BOPs or circulating through additional equipment and valves should be avoided in order to minimise potential damage by swarf to seals and seal areas.


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4.15

In the interests of subsequent equipment and drilling fluid maintenance, it is important that all remaining pieces of milled swarf be removed from the surface facilities on completion of operations. The mud pumps, lines and valves should be fully inspected. In addition to mud lines and pits, this should include the drip tray, trip tank, areas around and under the shakers and places forming natural traps. BOP ram cavities, kill and choke lines, standpipe and choke manifolds should be flushed.

5.

HOLE CLEANING/FLUIDS Successful milling depends upon the swarf being efficiently removed from the well. The procedures adopted must ensure that the formation of birds nests is avoided. The most important criteria for hole cleaning above all others is the annular velocity. At this time, there are no full guidelines available on pump rates, hole inclination and mill rates as there are for drilling. However, individual cases can be addressed. THE DRILLING PROGRAMME MUST STATE THE MINIMUM FLOWRATE TO BE USED. It should also be noted that at this time the flowrates will be tentative as the simulator used to develop the recommendation is working outside its original design specifications. The milling assembly must be designed to minimise pressure loss. Design must centre on maximising flowrate. By way of example only, the following illustrations of recent milling operations are given:

5.1

Operation

Casing Size

Behind Casing

Drillpipe

Deviation Deg.

Flowrate gpm

Window

9 5/8"

Cemented 12 1/4" OH

5"

50/60

520

Slot Recovery

13 3/8"

20" Casing Uncemented

5"

8/18

1350/1450

Slot Recovery

9 5/8"

12 1/4" OH

5"

59

750

Mud System - Selection of Mud Type The selection of mud type must take account of the following criteria: Surface handling system for swarf removal (personnel contact). Downhole torque (check drillstring simulator). Material behind the casing to be milled (requirement for shale inhibition). Logistics. a)

Oil Based/Water Based Mud In general, it is recommended that water based fluids are used. During the milling operation, a high degree of personnel contact with the fluid will be unavoidable in clearing birds nests, collecting and disposing of the swarf. Even with the appropriate protective clothing, use of an oil based mud will inevitably result in increased levels of skin complaints. Additionally, there is an increased risk of environmental pollution when milling with oil based mud.


BP EXPLORATION

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Water Based Mud Types If a water based fluid is used, then consideration must be given to possible shale inhibition requirements if the operation will expose water sensitive formations. In general, if the formation was previously drilled with oil based mud, a non-inhibitive water based mud can be used as the near wellbore formation will be oil saturated. If the formation was previously drilled with an inhibited water based mud, then an inhibitive milling fluid will be required. There are several types of water based milling fluid that can be used. These include: Bentonite/XC Polymer Bentonite/Sodium Bicarbonate Bentonite/Mixed Metal Hydroxide These are basic systems with no shale inhibition properties. Details on the fluids can be found in Sections 4100/GEN onwards of this manual. If shale inhibition properties are required, specific advice should be sought.

5.2

Mud Properties a)

Mud Weight When possible an unweighted system should be applied if a water based mud is in use as this will greatly assist logistics. When milling casing across open hole, the mud weight should be that as used to initially drill the section.

b)

Rheology The most important characteristics of the fluid from a swarf lifting consideration is its low shear rate rheology. This defines the viscosity of the fluid at the shear rate it experiences in the annulus. This is best expressed as the yield stress of the fluid, defined as: (2 x 3 rpm reading) - (1 x 6 rpm reading) The following rheological criteria are given as a guideline: PV YP Gels

cP lbs/100 sq ft lbs/100 sq ft

< 10 50 - 70 35 - 50

Note: With oil based mud, it will be impossible to achieve the low plastic viscosity criteria. 5.3

Mud Contamination Mud contamination by cement from behind the casing may require substantial additions of Sodium Bicarbonate to treat the presence of excess Ca ions. A large quantity of sodium bicarbonate should be available offshore as a contingency if required. Consideration to pre-treating the milling fluid prior to commencement of the milling may also be required. Should oil base fluids be behind the casing, the expected volumes, treatment and disposal, and containment will need addressing.


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6.

SECTION MILLING ASSEMBLY

6.1

Efficient operation requires the tool to be well centralised. The taper mill and pilot stabilisers should be the same size as the casing drift diameter. The section mill body diameter should be the largest available to comfortably run inside the casing so that the knives are as short, and as strong, as possible. Limit the number of drill collars to that required to provide the maximum anticipated milling weight. Jar placement should be determined for operating effect (keep above top of window at all times).

6.2

Recommended general assemblies (add crossovers as necessary): a)

Straight Hole Taper Mill - Near Bit Stabiliser - Section Mill - 4-6 DC - Jars - 1-2 DC HWDP.

b)

Deviated Hole Taper Mill - Near Bit Stabiliser - Short DC - String Stabiliser - Section Mill - 4-6 DC - Jars - 1-2 DC - HWDP.

Alternatives may be justified for specific tasks and sets of circumstances. 6.3

There is a danger of the connections below the section mill working loose with consequent loss of all or part of the pilot assembly. "Lock-up" type connections should be used if available, otherwise connections should be made up "dry" and use of a thread-locking compound considered.

7.

OPERATING PROCEDURES

7.1

Fluid circulation rates through section mills are limited by the size of the fluid courses and by the knifeactuating forces developed. If the tool features an interchangeable nozzle/orifice then the size selected should be consistent with a flowrate adequate for hole cleaning purposes.

7.2

The required diameter of the knife cutting circle will depend on casing string to cut/mill across an open hole section. The cut should be positioned 10 -1 5 feet below a casing coupling to make best use of the enforced stand-off between the strings.

7.3

Sets of knives can vary in shape, excessively high point-loading could result; check that each set, including spares, are similar. Hinge pins do sometimes bend in service; confirm that spares are available. If more than one style of tungsten/carrier matrix is available, confirm that the most suitable is used generally the hardest, most resilient category.

7.4

As with any downhole tools, ensure that all lengths and dimensions have been recorded before the assembly is run. Also confirm that suitable fishing tools are available.


SUBJECT: 7.5


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Function test the tool at surface. Pump through the tool at the "cutting-out" flowrate with the knife travel restricted to the casing ID (if practical) and then fully opened. Increase circulation to the full milling flowrate. Record the pressures at each stage, this is useful information when starting the actual operation. Check that the knives have opened fully to an even cutting circle.

7.6

Pin the knives back into the body with insulating tape, string or slivers of wood. If left loose, the knives are prone to hanging up in the wellhead and recesses in the casing string.

7.7

Drift the whole drillstring with proper, near-size rabbits. Loose cement or scale may block the tool or impair its operation.

7.8

Run the mill to the bottom of the proposed window to ensure that the casing bore is clean.

7.9

Pull back and take string up, down and rotating drags - without pumps.

7.10

Attempt to locate a casing collar so that the window may be accurately positioned. Using the casing running tally depths as a guide, start 20 feet above the expected collar depth and open the knives with a low pump rate. Run down slowly, without rotation, watching for a loss of string weight as the knives drop into a collar recess. Repeat the procedure to be sure. Finding the recess between Buttress-threaded joints should be straight-forward. Do not be surprised if it proves impossible to locate the relatively slight recess in a Vam casing coupling (try across a 90 foot interval to include 2 couplings).

7.11

Space out the drillstring to give maximum working height above the rotary table at the start of the cut. Floating rigs can be (de)ballasted to increase the interval between connections.

7.12

A marine swivel landed in the wellhead is required in making the initial cut from floating rigs. The other response of motion compensators when relatively low applied weight is required restricts the use of section mills to conditions of low heave amplitude. Repeated spudding/weight surging of the knives onto the open cut is likely to result in premature failure of the cutting structure.

8.

CUTTING AND MILLING OPERATION

8.1

Position the mill knives at the selected cut point and start rotation at 50 - 80 rpm, note the free rotating torque. Bring the pumps up to the "cut-out" rate (dependent on the size of tool and the internal nozzle fitted), note the pump pressure and the increase in rotating torque. Provided the torque fluctuations are within acceptable limits and the drillstring is running smoothly, allow the tool to make the initial cut - be patient, the cut may take 5 - 30 minutes. If the tool has a feature increasing the flow area when the knives fully extend (see Introduction, para. 2), a pressure drop will clearly indicate when the cut is completed. Torque changes will also be apparent. Be wary of heavy annulus fluids U-tubing into the well. Do not move the tool but increase pump speed to give the full operating flowrate while the cut is fully opened so that the knives can sit evenly on the casing.

8.2

Increase rotary speed and apply weight gradually to initiate a moderate milling rate (4 - 5 ft/hr, say). Continue at this rate for some time to establish that the milled cuttings and swarf are being removed from the hole in appropriate volumes. Once satisfied that the hole is being cleaned and that the volume of swarf can be handled on surface, the milling rate can be further increased.

8.3

The best rotary speed and weight on mill have to be determined for each job, experiment systematically to find the parameters which result in smooth running and a good rate of progress.


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8.4

Maintain a steady weight by allowing the drawworks to creep and feed drilling line evenly. Do not allow the weight to drill-off each time before slacking off line.

8.5

Mark the pipe at the rotary table in 1' intervals and record milling data on a proforma sheet for each increment: Depth

Time

ROP

RPM

WOB

Torque

Flowrate

Pressure

8.6

Increases in pump pressure are the first indicator of a hole cleaning problem, swarf will aggregate and pack-off the annulus in a downhole "birds nest". Reductions in swarf volume at the shakers suggest a near surface accumulation or blockage.

8.7

Pump pressure increases may be small (less than 50 psi) or so large that the pumps have to be slowed or even stopped. Cease milling and work the string to attempt to clear the birds nest. If the nest is in the riser, a means of disturbing it is to pull back far enough so that a stabiliser can be made up into the string and then worked down to the wellhead. If a top drive is used, then a stand with a stabiliser at the bottom should be racked back to save time in picking it up.

8.8

Removal of a nest around the drillstring at the bell nipple will require some form of grab or a barbed rope spear to be available for running on a drillfloor tugger.

8.9

Pumping a hi-vis pill after each casing coupling has been milled is recommended. If the flowline is prone to blockage, then it may be advisable to stop milling and flush or rod it periodically before it blocks completely.

8.10

Casing couplings will mill more slowly and may require reduced rotary speed or greater weight. Most non-integral couplings are not threaded to the very end, as a result the unthreaded portion breaks free as the mill knives approach the lower end of the coupling. The loose ring may break up or become trapped and milled, however it may also start to spin on the top of the remaining casing at any stage, preventing the mill from biting. If this occurs then gentle spudding on the ring should cause it to break up or become distorted and trapped so that it can be milled up. Stop rings and centralisers can cause a similar result and should be treated accordingly.

8.11

If drillstring is bouncing or rough running starts to occur, then the weight and rotary speed should be reduced for a while before attempting to gradually increase the parameters again.

8.12

Poorly cemented casing may necessitate lower rotary speeds with less applied weight.

8.13

As the knives become completely worn down, the casing will be skimmed for a while before the tool starts to fall down inside - watch for torque changes and increased ROP at low weights. Pull back and locate the true lower end of the window by running down without rotation to sit the worn knife stubs on the casing.

8.14

Once the window is complete, or the knives worn out, ensure that the hole is circulated clean before POOH. The point at which changes in swarf size/form and volume is observed at the shakers can provide a good indication of the efficiency of hole cleaning. Turn off the pumps and rotate the string for a few minutes to persuade the knives to collapse into the tool body. Take care when withdrawing the mill and stabilisers back through the top of the window.


SUBJECT: 8.15

8.16


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If the window is not completed with the first mill run, then the following precautions should be observed on subsequent runs: a)

Break circulation above the casing window to confirm that the knives do close again afterwards.

b)

Open the knives at the top of the window and lightly ream through the section - set torque limiter at minimum position to maintain rotation only.

c)

Cut a profile on the casing stump with the new knives at minimal weight before resuming the window.

A subsequent run with a rock-type underreamer may be considered if it is vital to remove all debris from the window or to produce a consistent open hole diameter.

BP EXPLORATION

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SUBJECT: CASING MILLING AND UNDERREAMING FOR OPEN HOLE GRAVEL PACK 1.

INTRODUCTION Casing Section milling operations are comprehensively discussed in Section 6420/GEN of the Drilling Manual. This section gives additional guidance on section milling and underreaming operations from a Semi-Submersible required to open a section of casing in order to complete an open hole Gravel Pack Operation. It should be read in conjunction with the Section 6420/GEN and 6300/GEN. Milling and underreaming operations for an open hole gravel pack have been carried out on the Sea Explorer in 1992 as follows: Donan Well 15/20a-6RE

14m of 29 lb/ft L80 VAM liner at 51 degrees deviation

The lessons learnt and the techniques followed during this operation are recorded for future use. The major operational differences between the Gravel Pack operation and conventional milling operations are:

2.

1.

Accuracy of milled section. The milled section required for gravel pack operations is equivalent to the perforated interval required on conventional wells, therefore similar accuracies to ensure the milled section is on depth are needed.

2.

The required interval for carrying out a gravel pack operation will not always coincide with the optimum location for section milling operations. The section milling operation may therefore involve additional risks that would be avoided on normal section milling jobs.

3.

Rig Movement. Operations must take account of the rig movement when milling from a SemiSubmersible Unit. This is especially relevant in highly deviated wells. The combination of high drags and rig heave can seriously hamper depth control and the overall success of the milling and underreaming operation.

4.

Solids Contamination of the System. The milled section is required to be used for Gravel Pack Operations, consequently all operations required to achieve this must be planned to minimise any formation damage.

5.

The section to be milled will generally be across a hydrocarbon bearing reservoir. Although well control measures should be considered in all section milling operations, they become more critical in the reservoir section.

6.

The section to be drilled will generally have a small ID, requiring small, fragile tools, which are very sensitive to applied loads.

SELECTION OF INTERVAL The interval to be milled is dependent on the required Gravel Pack Interval as determined by Petroleum/Reservoir Engineering considerations, however at the planning stage it is critical to assess the additional risks of milling the desired section, i.e: 1.

Condition of cement behind casing. Consult CBL/VDL and CET logs to determine the condition of cement behind the casing. It is unlikely that the Petroleum/Reservoir Engineering requirements for zone isolation would be satisfied if the cement bond was poor, however poorly cemented casing will result in possible milling difficulties due to lateral play of the cut casing.

2.

Consult the casing tally to determine the position of casing collars and cementing jewellery behind the casing. If the selected interval starts immediately below a casing collar, there is additional risk of the casing stub backing out and dropping onto the cutting assembly. In well cemented casing, the milled section has been successfully milled from 3m below a casing collar.

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SUBJECT: CASING MILLING AND UNDERREAMING FOR OPEN HOLE GRAVEL PACK

3.

4.

3.

It is not necessary to mill a large safety margin above the milled window. Both the section milling tool and underreamer will be referenced to the same depth and should be successfully open within 0.3m of the required depth. The underreaming operation should be designed to start about 0.5 below the top of the milled window.

4.

Avoid milling and subsequently underreaming mudstone sections at the top and bottom of the interval as this will incorporate unwanted drilled solids into the fluid system which may result in formation damage.

5.

If the section to be gravel packed has been identified prior to running casing/liner, Bakerlock the casing joints at the top of the window. Ensure the casing is well centralised immediately above and below the section to be cut but minimise the use of bowspring centralisers and stop collars in the section to be cut. All cementing jewellery across the section should be selected to minimise the possibility of rotating when being milled. Ensure a Radioactive marker is run in the casing approximately 60m above the top of the interval.

PREPARATION 1.

The interval to be milled and underreamed should be agreed with Petroleum/Reservoir Engineering and the Asset Group and should be referenced to a specific Log.

2.

A good copy of the CBL/VDL/GR showing the RA marker, interval to be cut and the top of the liner PBR should be available on the rig. Ensure that this log is on depth with the Reference Log.

4.

The top of the liner PBR should have been dressed off to ensure that there is no cement above the top of the PBR as this will be the reference depth where the cutting assembly will land off.

SWARF REMOVAL AND HANDLING 1.

The initial cut should be made in a separate run using a casing cutter and marine swivel assembly in order to compensate for the effects of heave. The distance from the PBR to the casing cut should be accurately determined from the CBL/VDL log. A casing cutter will be used to make the initial cut in order to give at least a 4 inch cut to ensure that the following section mill run will positively locate in the cut section. Use of a section mill to make the initial cut would result in a smaller cut being made and may result in difficulty locating the cut section, especially if the well is highly deviated.

2.

Recommended general assembly: For cutting 7" liner: 6" (for 29 lb/ft casing) Taper Mill with stabilised section 5 9/16" Pipe Cutter c/w 11 1/2" opening knives 6" stabiliser (for 29 lb/ft casing) 1 stand 3 1/2" drillpipe 3 1/2" IF RA marker sub 3 1/2" Drillpipe and pup joints 8 1/4" OD Marine Swivel 1 x HWDP DS 14 x HWDP 5" DP to surface The length of 3 1/2" drillpipe and pup joints should be chosen so that the cutter knives are on depth with the Marine Swivel landed on the PBR. Ensure a good selection of different length pup joints is available on the rig.

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SUBJECT: CASING MILLING AND UNDERREAMING FOR OPEN HOLE GRAVEL PACK For cutting full string 7" casing: The appropriate Marine Swivel to land in the wellhead should be used. 3 1/2" pup joints should be placed at the top of the string to allow them to be changed out if the string is pulled back to adjust the spaceout. Due to stretch in the string and the effect of torque and pumping forces shortening the string, this spaceout will not be as accurate as when the Marine Swivel is landing on the liner top. The length of knives used should be long enough to produce a minimum 4" high cut in the casing to enable the section mill to locate positively in the cut. All tubulars between the casing cutter and the RA Marker sub should be measured and tallied independently by the Drilling Contractor and the BP Rep/DE to ensure that the critical spaceout is correct. Steel line strap the string from the casing cutter to the Marine Swivel. Drift the string to ensure GR/CCL tool will pas through string to top of cutter. There is a danger of connections below the section mill working loose with consequent loss of part of the pilot assembly. Lock up type connections should be used if available, otherwise connections should be made up "dry".

5.

3.

Function test the operation of the cutter on surface prior to running. Wedge or tape the knives back in place. Do not break circulation when running in the hole as the knives are likely to open, preventing the string from entering the PBR.

4.

Record up/down/rotating weights prior to landing the Marine Swivel. 40 ft bails should be rigged up for wireline logging before landing.

5.

Rotate the string slowly and land off the Marine Swivel on the PBR. Slack off 10,000 lbs.

6.

Rig up electric wireline through drillstring. Run GR/CCL log to confirm depth of casing cutter. Ensure the wireline is compensated relative to the string. If the casing cutter is not on depth, the string will have to be pulled back to below the Marine Swivel and the spaceout adjusted using pup joints.

7.

Rig down the wireline and 40 ft bails and make up top drive/kelly.

8.

Rotate the string slowly and re-land the Marine Swivel with 6-8000 lbs. The response of motion compensators with low applied weight is often poor. If the rig heave dictates, slack off additional weight on the Marine Swivel, within its operating limits, to ensure the swivel does not bounce during the cutting operation, leading to failure of the knives. Slack off weight should not exceed 15,000 lbs.

9.

Make the cut as per Section 6300/GEN.

SECTION MILLING OPERATION Section milling operation should be carried out in accordance with Section 6420/GEN. 1.

Recommended General Assembly: For Section Milling 7" Liner 6" Taper Mill (for 29 lb/ft 7" liner) 5 1/2" Section Mill Jetted Top Sub X/O as required 1 x 4 3/4" DC

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SUBJECT: CASING MILLING AND UNDERREAMING FOR OPEN HOLE GRAVEL PACK RA Marker Sub 8 x 4 3/4" DCs Jar 2 x 4 3/4" DCs 3 1/2" DP 5" DP The use of a circulating sub (preferably a re-cockable sub, as supplied by PBL) is strongly recommended, to allow a high rate clean-up above the PBR, and the break up of birdsnests. The jetted top sub is run to increase the circulating rate to improve hole cleaning whilst ensuring sufficient differential pressure is applied across the section milling tool for it to operate. Sizing of the jets should be carried out in conjunction with the Section Milling Service Company, based on the recommended flowrate required to keep the hole clean. Ensure the top sub is jetted to the minimum acceptable size, and that at least 30% of the flow is directed through the section mill tool, otherwise there may be insufficient hydraulic horsepower available to keep the cutters open, and tell-tale pressure drops will be less evident. A dart sub should be run in the string. 2.

The cutting structure of the Servo "Millmaster" has a proven track record in producing small metal chippings; this is essential for good hole cleaning.

3.

After section milling the required interval, perform a cleanout trip to remove any cuttings and swarf in the milled section. Use a taper mill/string mill assembly. A PBR dressing mill should be available on the rig to clean up the top of the liner. Whilst running in hole, break circulation and circulate regularly to prevent running into swarf and packing off.

Drilling Fluid Requirements 1.

Section milling fluid systems are discussed in Section 6420/GEN. Ensure that any filtrate invasion from the selected fluid will be non-damaging to the reservoir.

2.

The combination of high YP (50-70) required for hole cleaning and swarf removal, the small annular clearance between the section mill assembly and the selection of the section mill fluid bypass area will result in a considerable swab and surge pressure being generated when moving the assembly. There is also the possibility of swarf birdsnests forming which will also create swabbing problems. It is critical that swab and surge calculations are performed in the planning stage when specifying the density of the milling fluid. Sufficient trip margin must be allowed for. The normal 200 psi drilling overbalance will not be sufficient in many cases. Trip speeds must be restricted to ensure a safe overbalance is maintained.

3.

High mud YPs may also result in oil or gas entrainment in the mud which will be difficult to remove. The mud should be routed through the degasser to remove the gas, however progressive circulations may not bring the gas levels down quickly.

4.

Fine milled cuttings may be produced during the section milling operation which will increase formation damage. Returns should be routed through the mud cleaner to maximise removal of all drilled/milled solids. Ensure ditch magnets are located in the returns trough throughout the milling and underreaming operations.

5.

When section milling 7" liner or casing, due to the low circulating rates and annular velocity, it will be necessary to circulate the riser clean using a riser boost line or through the kill or choke line. This will help in the prevention of a birdsnest forming in the riser.

6.

The milling fluid should be displaced to a non-damaging underreaming fluid during the cleanout trip at the end of milling operations. The mud pits and entire surface circulating and mixing system

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SUBJECT: CASING MILLING AND UNDERREAMING FOR OPEN HOLE GRAVEL PACK should be thoroughly cleaned and flushed to remove all solids contamination that may result in formation damage. The Fluids policy should identify all measures to be taken to clean the mud system and displace to the underreaming fluid. 7. 6.

Operate BOP rams during flushing process to remove swarf from cavities.

UNDERREAMING OPERATION In order to underream the gravel pack zone to the required hole diameter, a 3 bladed drag type underreamer will be required. Cutters should be selected to be able to cut and remove any steel remaining in the interval without destruction of the blades, i.e. Smith tungsten "Millmaster" cutters with diamond enhanced gauge protection. The cutter opening diameter will be dependent upon the gravel packing requirements. The 5 7/8" Servco underreamer provides a maximum cut of 14". This maximum cut should be avoided due to the additional stresses on the blades when underreaming in the presence of junk, and in unstabilised over gauge hole. Over stressing of the blades may lead to a failure of the body or blades. Select the minimum blade size required to satisfy the gravel pack criteria. A full NDT inspection of the Drag type underreamer high stress areas should be carried out before shipping to the rig. This should include the internal areas at the reduced cross section of the blade retaining pins. Full material traceability of the underreamer is required. It is recommended for work in small diameter holes, that the tool is especially manufactured from a high strength alloy (if time allows). Particular attention should be paid to Charpy notch toughness values. 1.

Recommended General Assembly: For 7" liner 5 3/4" drag type underreamer Bit Sub Short DC 6" String Stab Short DC 6" String Stab 1 x 4 3/4" DC 6" String Stab 1 x 4 3/4" DC RA Marker Sub 11 x 4 3/4" DC Jar 2 x 4 3/4" DC 3 1/2" DP X/O 8 1/2" Soft Bladed Stab 1 x HWDP DS 2 x HWDP 5" DP to surface The 8 1/2" stabiliser is run to correlate the depth relative to the top of the PBR. It should be spaced out to tag the top of the PBR when the underreamer is approximately 20m below the bottom of the underreamed section. This will allow the string to be worked below the cut section if required. If a full string of casing has been run, then the stabiliser will not be run. Correlation will have to be made with a GR/CCL logging tool using the RA marker subs in the casing and underreaming string.

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SUBJECT: CASING MILLING AND UNDERREAMING FOR OPEN HOLE GRAVEL PACK All tubulars between the casing cutter and the RA marker sub should be measured and tallied independently by the Drilling Contractor and the BP Rep/DE to ensure that the spaceout is correct. Steel line strap the string from the underreamer to 8 1/2" stabiliser. Drift the string to ensure GR/CCL tool will pass through the string to the top of the underreamer. In high angle holes, or when the underreamed section is greater than 15m long, a pilot assembly below the underreamer may be necessary to prevent the risk of sidetracking. A taper mill and 6" stabiliser should be used below the underreamer. There is a danger of connections below the underreamer working loose with consequent loss of part of the pilot assembly. Connections should be made up "dry". 2.

Function test the operation of the underreamer on surface prior to running. Ensure the knives retract when the pumps are stopped. If the underreamer does not have a positive opening system, tape or wedge the knives in the closed position. Do not break circulation when running in the hole as the knives are likely to open preventing the string from entering the PBR. If the string has to be filled whilst running in the hole, ensure the fluid density is the same as that in the hole. A hydrostatic differential between the string and the annulus may be sufficient to open the knives preventing entry into the PBR.

3.

Record up/down rotating weights prior to entering the open hole section.

4.

Rotate the string slowly and tag the PBR with the 8 1/2" stabiliser to give an accurate depth for the underreamer. Strap out of the hole to put the underreamer at the top of the section to be underreamed. Hold the string in this position until the arms have fully opened. Adjust the pipe tally to ensure the maximum interval can be underreamed prior to making the first connection.

Note: The response of motion compensators to low applied weight on bit is often poor. Success of the operation relies heavily on maintaining steady operating parameters. The underreaming operation should therefore not be attempted in more than 2-3 feet of rig heave. 5.

Bring up the pumps without string rotation and record the pressure with the underreamer arms in the closed position. Stop the pumps. Start rotating the string. Bring up the pumps smoothly to the pre-recorded rate to start opening the underreamer. Monitor the pump pressure closely to observe the tell-tale pressure drop indicating when the knives have fully opened. Slowly set weight on bit to establish a cutting shelf.

Note: Do not rely solely on the tell-tale pressure drop to indicate the arms are fully open. The pressure drop may not be very evident, and at the beginning of circulation other factors may cause pressure drops. 6.

Continue underreaming the interval. As soon as a steady underreaming torque has been established, set the torque limiter to slightly above this level to keep the string rotating. Monitor closely the torque and progress when approaching milled casing collars, centralisers or other signs of junk.

7.

At the end of the interval, stop rotating and with pumps on tag the top and bottom of the underreamed interval to confirm the full interval has been cut.

8.

Perform a cleanout run with a taper mill and string mill assembly to ensure there are no obstructions through the underreamed section.

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SUBJECT: CASING MILLING AND UNDERREAMING FOR OPEN HOLE GRAVEL PACK 7.

CONFIRMATION OF UNDERREAMED INTERVAL 1.

A GR/CCL/CAL log can be run to confirm the hole gauge and section length over the underreamed interval.

2.

To allow for tide, run a line from the top of the riser to the drill floor. Knot the line, and mark the drill pipe. Drill the required interval, and check directly against the position of the knot.

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BIT NOZZLE REMOVAL

1.

Under certain conditions it is desirable to remove the nozzles from a bit downhole to enable free passage of plugging/lost circulation materials. Nozzles, whether retained by circlips or nails, can be removed using explosives.

2.

In order to use sufficient primer cord the minimum acceptable ID in the drill string should be 2 1/6”.

3.

The charge is made up on a firing head of 3/8” mild steel bar approximately 7 ft long with a 1” OD X 2” long bull nose on the bottom (the basic string shot tool). One strand of primer cord is used for detonation, with twelve lengths of 16” long primer cord laid along the bottom part of the bar. Wrap approximately 3 ft primer cord around the 12 lengths at approximately 9” from the bottom of the tool. Finally wrap plastic tape over the cord to hold the charge in place. (80 gain primer cord is to be used throughout). The maximum OD of the charge should be 1 3/4”.

4.

Usually string connections adjacent to the bit will be slackened by this operation - care must be exercised when tripping out afterwards.



Index Prefixes 0000


1000

Drilling

2000

Casing and Tubing

3000

Cementing

4000

Drilling Fluids

5000


6000


7000

Well Evaluation

8000






Section

Description

7000

WELL EVALUATION

7005/GEN

Loading, Setting, Timing and Operation of Dropped Survey Barrel

7100/GEN

Leak-Off Testing

7200/GEN

Coring

7210/GEN

Oriented Coring

7220/GEN

Extra Long Core Barrel

7300/GEN

Mud Logging Services

7400/GEN

Electric Logging Operations Using Pressure Equipment


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LOADING, SETTING, TIMING AND OPERATION OF DROPPED SURVEY BARREL EQUIPMENT

ANADRILL MAGNETIC SINGLE SHOT OPERATION EASTMAN ELECTRONIC TIMER Surface Check 1.

If not already assembled, screw the battery pack and electronic timer together. Load 3 fresh “C” size alkaline batteries, tip end (+) down,into the battery pack and install the end plug.

2.

Slide the camera into the electronic timer and firmly hold it in. Set both time delay switches to zero. Then depress start button. Check the camera lights - should immediately turn on for 7.5 seconds and then turn off. Remove camera from the timer.

Loading the Camera 3.

Select the desired angle unit.

4.

Screw the angle unit and camera together*, a snug fit is all that is required.

5.

Place the film loader onto the camera and angle unit assembly. * Be sure to fully engage the film loader’s lips into the camera’s disk trap slot.

6.

Hold the film loader firmly to the camera and angle unit assembly. Depress and hold the film trap and release button with the index finger of the hand holding the assembly.

7.

Cycle the film ejector in and then out to insert the film disk into the camera.

8.

Release the film trap button*. You should be able to feel the film trap close as you let go of the button. Remove the film loader from the camera. Inspect the film trap cover to make sure it is closed completely. If the cover did not close, the film must be removed, the problem corrected and a new film loaded.

Loading the Instrument 9.

Initialise the camera triggering device. Clear the timer by setting the timer delay switches to zero and depressing the start button. Wait 15 seconds.

10. Make up the camera/angle unit to the timer/battery assembly. 11. Just before you load the instrument into the pressure barrel, set the required delay time for the instrument to reach the bottom of the hole, settle the angle unit and expose the film. Survey Running Gear 1.

As a rule of thumb, in low angle holes with a 12 - 15 ppg mud weight, the instrument will free fall approximately 1000 feet per minute. Free fall will decrease with larger hole angles and heavier mud weights.

2.

Typical wireline in run speeds are 500 - 700 feet per minute depending on the hole angle and mud weight.

3.

Make sure you allow sufficient time for assembling the running gear and rig preparation time to go in the hole.

Running the Survey The single shot instrument can be run into the hole and then removed using one of three methods:

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1.

Dropping the instrument and recovering it with the drill string.

2.

Dropping the instrument and recovering it with an overshot.

3.

Running the instrument in and out of the hole on a wireline.

Some basic considerations: a)

Check the running gear for proper make-up (ensure the overshot fits the spear point).

b)

Make sure the drill string is full of fluid.

c)

Break off and set back the kelly.

d)

Drop the instrument. Do not rotate the drill string while the instrument is in the string. However, if you must rotate the drill string, do so very slowly. Yo-yo the drill string if you must move the string to avoid sticking. Idle the pumps if circulation must be maintained.

e)

Stop the drill string motion and the pumps for 30 seconds before and after “picture time”.

f)

Record the hole’s measured depth when the survey was taken.

g)

Retrieve the survey instrument at surface, rinse with clean water.

h)

Slide the instrument out of the pressure barrel.

i)

Unscrew the electronic timer and battery assembly from the camera and angle unit.

Unloading and Developing the Film 1.

Pull apart the unloader/developing tank. Rinse the inside with fresh water and dry. Make sure the unloader’s light trap handle moves freely.

2.

Fill the tank with 1/2” of Developing and Fixing Fluid.

3.

Place unloader on a flat surface and open the unloader light trap.

4.

Place the camera and angle unit assembly over the unloader and mate the lips of the unloader with the film gate notch in the camera. While the camera is firmly mated to the unloading tank, depress the camera’s film gate release button.

5.

Shut the unloader’s light trap gate.

6.

Shake the unloader from side to side, ensure the film is lying horizontal with no air bubbles underneath.

7.

Let the film develop for 4 minutes, if fluid is cold (below 68°F) allow between 8 - 10 minutes.

8.

Carefully remove film disc from the tank. Rinse with fresh water and dry with a lint cloth.

Reading the Film 0° - 10° and 0° - 20° Film Disks: 1.

Place the reader over the film disk.

2.

Count the number of circles from the disk centre to the plum bob “crosshairs”. Read the inclination to the closest 1/4° degree.

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3.

Read the hole direction by lining up the reference line on the disk reader so that it intersects the centre of the film disk and the centre of the film disk’s plumb bob crosshairs.

4.

The film reader’s reference line must extend through the compass scale around the circumference of the disk.

5.

The intersection of the reader’s reference line and the compass scale corresponds to the hole direction.

15° - 90° Film Disks: 1.

The film disk reader reference line is not used with the 15° - 90° film disk. The reader is only used for magnification.

2.

Read the inclination at the intersection of the disk’s centre horizontal crosshair and the vertical scale, read to a 1/4° degree.

3.

Read the hole direction pointed to by the bottom of the vertical centre line, to the nearest degree.

Orientation For 0° - 10° or 0° - 20° angle units, the angle pointed to by the orient line, after applying the magnetic declination correction, is the tool face. For 15° - 90° angle units, align the survey picture with the film reader as shown. Read the tool face from the reader’s scale, and then apply the declination correction.

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MAGNETIC SINGLE SHOT OPERATION EASTMAN ELECTRONIC TIMER

END PLUG

BATTERY PACK

ELECTRONIC TIMER

CAMERA

ANGLE UNIT

SURVEY RUNNING GEAR SPEAR POINT

WIRELINE ADAPTER

SWIVEL

ROPE SOCKET RUBBER STABILISER PIN SPACER BAR

PRESSURE BARREL; BULL PLUG *

RUBBER PIN STABILISER BODY

O-RING

PRESSURE BARREL

LANDING SPRING SINGLE SHOT INSTRUMENT ASSEMBLY

*

*

O-RING

SINKER BAR(S) OR SPACER BAR(S)

*

PRESSURE BARREL BULL PLUG * TAPERED ON 'R' SINGLE SHOT

BOTTOM LANDING SHOCK ASSEMBLY 910303 / 1

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ANADRILL: READING SURVEY DISCS

ORIENTATION EXAMPLE HOLE DIRECTION 2

3

7 8W8 7 6 5

7 8E8 7 6 5

56

5 6

43

43

43

2 1S1 2 3

4

S

30 20 10

7 8W8 7 6 5

E

5

56

10 20 30 40 50 60 70

70

7 8E8 7 6 5

5

50 40

30

8

RIGHT

10 9

11

7 8E8 7 6 5

2 1S1 2 3 4 12

5

12 14

56

13 17 18 17 16 16 15

7 8E8 7 6 5

40 1 50 2 60 3 70 80 4 5 80 6

15

5 56

56

LEFT

13

LUBBER LINE

56

2 1N1 2 3 4

7 8 9

12

ORIENTATION EXAMPLE

43

80

30

5 80 6

9 10 1 1

ORIENTATION 180 LINE DIRECT METHOD TOOLFACE

'E/R' 0 - 20° DISK INCLINATION = 12.0° DIRECTION = N60°W

2 1S1 2 3 4

INCLINATION LINE

40 1 50 2 60 3 70 80 4

14

2 1S1 2 3 4 12

7

S

10 20 30 40 50 60 70 80

E

'R' 0 - 10° DISK INCLINATION = 5.0° DIRECTION = N65°W

4

70

7 8W8 7 6 5

SINGLE SHOT CROSS HAIR

50 40

30 20 10

56

7 8W8 7 6 5

5

56

4

3

8

2 1N1 2 3 4 43 12

2

7

1N1 2 3 32 4

1

1

4

6

0° - 20°

5

0° - 10°

7 8 9

34

43

2 1N1 2 3 4 12

7 8W8 7 6 5

2 1N1 2

5

43

43

7 8E8 7 6 5

56

56

43

2 1S1 2 3 4

ANADRILL: READING SURVEY DISCS

ORIENTATION LINE DIRECT METHOD TOOL FACE N20°W HOLE DIRECTION N45°E

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EASTMAN CHRISTENSEN ELECTRONIC SINGLE SHOT TIMER Selectable time delay of 1 to 99 minutes (1 min increments). Battery pack requires 3 x “C” cell batteries, tip ends (+) loaded into battery pack towards timer. Test Procedures •

Screw battery pack onto electronic timer.

•

Place camera into timer and hold firmly in place.

•

Put both switches on timer to zero.

•

Depress start button on timer.

•

Camera lights should come on and red LED should flash for 7.5 seconds and then turn off.

Running Procedures •

Re-set timer by setting both switches to zero and depress start button - wait 15 seconds.

•

Make up camera and angle unit, load disk into camera. Do not load disk into camera before it is connected to the angle unit or disk will be exposed.

•

Connect to battery pack/timer assembly. Just before loading instruments into pressure barrel, set the required delay time on the switches. Press the start button and start your stop watch simultaneously.

•

Observe the timers LED, it should flash for the first minute indicating correct operation.

Unloading and Developing the Film •

Recover the instruments and unscrew the camera/angle unit assembly from the timer. DO NOT separate the camera from the angle unit at this stage or the film will be exposed.

•

Pull the bottom of the developing tank off. Make sure the tanks light trap operates freely (normally firm). Fill the bottom of the tank with 1/2” of developing fluid. Push the top of the tank completely into its bottom cup.

•

Place the tank on a firm surface and open the light trap.

•

Place the camera/angle unit over the tank and mate the lips of the tank with the film gate notch in the camera. Press the camera’s film gate release button. Shut the tanks light gate.

•

Allow the film to develop for four minutes, agitating the tank occasionally. If the fluid is cold (below 68 deg.F) develop the film for 8 to 10 minutes.

Reading the Film •

0 - 10 and 0 - 20 disks - line up the readers cross hair so that it intersects the centre of the disk and the centre of the plumb bob cross hair. Where the readers cross hair intersects with the compass card, read the direction, read inclination from where plumb bob cross hair intersects concentric inclination circles.

•

15 - 90 disks - read the inclination at the intersection of disk’s centre horizontal cross hair and the vertical scale. Read the direction pointed to by the bottom of vertical lubber line.

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Running Gear Assembly •

The pressure barrel assembly contains the timer, battery pack, camera and angle unit, in a water tight, pressure proof, non-magnetic barrel. The barrels protect survey instruments from drilling mud and hydrostatic pressures to 26,000 PSI.

•

Verify that the correct baffle plate is installed and what its position is, in the bottom hole assembly.

•

Check that the minimum drill string ID is large enough to allow the survey tool to pass through to the bottom.

•

If the survey instrument will be subjected to temperatures over 250 degrees F, heatshields must be used.

•

If the tool is to be dropped inside the drill string, then a spearpoint must be placed at the top of the tool. Ensure that the correct overshot is available and is operating correctly.

•

Running gear should be assembled as per the drawing.

•

Tandem surveys will always be run. The box-box crossover is supplied in the instrument box.

•

Ensure bull plug “O” rings are in good condition, if there is any doubt, change them.

•

Sinker bars must not be used on tools which are to be dropped inside the drill string.

•

Use the correct amount of spacer bars to ensure the instruments are correctly spaced inside the non-magnetic drill collars.

•

The instrument package can be suspended from the upper bull plug on the rubber shock absorber or seated on the rubber shock absorber attached to the lower bull plug, an adaptor is provided in the instrument box for this option. Whichever method is used, the angle unit must be at the bottom of the instrument, i.e. downhole.

•

As a general rule of thumb, in low angle holes with 12 - 15 ppg mud, the tool will free fall at approximately 1000 feet per minute. Free fall speed will decrease with increased hole inclination and heavier mud weights.

•

Do not pump a tool to bottom in a vertical well.

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EASTMAN CHRISTENSEN SURVEY BARREL COMPONENTS

EASTMAN CHRISTENSEN SURVEY BARREL COMPONENTS ELECTRONIC SINGLE SHOT TIMER

END PLUG

BATTERY PACK

CAMERA

ELECTRONIC TIMER

ANGLE UNIT

SURVEY RUNNING GEAR SPEAR POINT

WIRELINE ADAPTER

SWIVEL

ROPE SOCKET RUBBER STABILISER PIN

PRESSURE BARREL BULL PLUG O-RING

PRESSURE BARREL

SWIVEL RUBBER PIN STABILISER BODY

O-RING

O-RING

PRESSURE BARREL BULL PLUG

BOX/BOX X-OVER


PRESSURE BARREL

O-RING


SINKER BAR(S) OR SPACER BAR(S)

BOTTOM LANDING SHOCK ASSEMBLY 910303 / 3

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EASTMAN CHRISTENSEN - READING SURVEY DISCS

56

2 1S1 2 3 4 12

5

2 1N1 2 3 4 12

7 8W8 7 6 5

43

56

43

56

7 8W8 7 6 5

7 8E8 7 6 5

2 1N1 2 3 4

56

43

5

7 8E8 7 6 5

EASTMAN CHRISTENSEN - READING SURVEY DISCS

43

2 1S1 2 3 4

SINGLE SHOT READER CROSS HAIR 'R' 0 - 10° DISK INCLINATION = 5.0° DIRECTION = N65°W

'E/R' 0 - 20° DISK INCLINATION = 12.0° DIRECTION = N60°W

INCLINATION LINE

80

30

E

30 20 10

70

7 8 9

50 40

33.0° S 35°E

S

INCLINATION DIRECTION

40 1 50 2 60 3 70 80 4 5 80 6

10 20 30 40 50 60 70

SUBJECT:

Section

LUBBER LINE

910303 / 4

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SMITH SINGLE SHOT OPERATIONAL PROCEDURES Operational Steps of the Single Shot Electronic Timer 1.

Screw the battery pack (containing 4 “C” size alkaline batteries) onto the end of the electronic timer. (Note: Positive or tip ends down toward the timer.) The electronic timer has a reverse polarity protected circuit so that if the batteries are installed upside down and the timer start button is pressed, the timer will not start nor will any of the circuitry be harmed. Merely re-install the batteries with the (+) tip down toward the timer.

2.

The timing interval is set using the three rotary switches. Turn the switches in any order to the desired timing interval reading left to right. (Note: X1 = units place, X10 = tens place, X100 = hundreds place.) The total timing interval is the sum of the time indicated on the three switches.

3.

Insert the camera into the cover tube of the electronic timer prior to loading it with film. It may be necessary to press the camera against its spring contact to ensure good electronic contact while checking the bulbs.

4.

Once the timing interval switches are set, press and hold the red TEST-STOP button to check bulb, battery and timer operation. While holding the TEST-STOP button down, press and release the black timer START button. The electronics will now revert to seconds timing corresponding to the decade switch settings instead of standard minute timing. Once every second, the LED (light emitting diode) will flash until the timing interval in seconds is timed out. At this point the LED will stay on and the camera bulbs will light. Both systems will stay lighted for approximately 13 seconds.

5.

After loading and making up the camera and angle unit and assembling them to timer and battery pack, the instrument is ready to be put into its protective barrel. If the preceding test procedure described in step 4 has been carried out and the decade switches are set to the necessary timing interval, the operator needs only to press the black timer START button while simultaneously starting his surface watch. He should observe to see that the LED is flashing at the rate of once per second. If so, the instrument is ready to go downhole.

6.

To change the time interval setting after starting the timer sequence, the operator presses the red TEST-STOP button. This stops and re-zeros the timing count, allowing the new setting to be dialled into the decade switches. To start the timer again on the new setting, press the black START button. This will cause the LED to flash.

7.

After removal from downhole, the camera and angle unit can be removed from the timer, the camera unloaded and the picture developed. Note: It is suggested that between surveys the instrument be stored in its kit box with the angle unit and camera assembled to the timer. To insure extended battery life, it is suggested the battery pack be removed between surveys.

Camera Unloading Loading a film disc into the camera is accomplished by using the following steps 1 through 7: 1.

Screw the camera unit onto the angle unit.

2.

Take the film loader and place it onto the camera unit making certain that the pin on the film loader face engages with the matching hole below the disc trap. When this occurs the extended lips on the loader engage and enter the disc trap slot properly. This is to insure total absence of light during the loading process.

3.

Holding the disc loader and camera/angle unit between the thumb and second finger, press knob with the index.

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4.

While depressing knob, pull the disc loader slide all the way out. Then push the slide completely in again. (If the slide will not go back into the loader, the loader is empty of film.)

5.

Release knob and remove loader.

6.

If the red line around the outside diameter of knob and a red dot on the slug trap slide are both visible, then no film disc was transferred to the camera.

7.

Screw the loaded camera/angle unit assembly into the cover tube of the electronic timer.

Camera Unloading and Development of Survey Picture 1.

Prior to unloading the film disc, there are certain precautions that should be practiced with the developing solution to insure good quality pictures. All developing solution should be stored in a cool location and out of direct sunlight. Each time the bottle is opened it should be squeezed to exclude as much air as possible before the cap is replaced. If the developing solution is colder than 68°F (20°C) there will be considerable loss in picture resolution. The developing solution can be checked by loading a disc into the camera and unloading the disc into the developing tank filled with developer. Not having been exposed, the disc should come out clear. Note: Film within the loader may also be checked by ejecting a disc into the hand in daylight. Then load it into the developing tank solution and develop it. This disc should come out entirely black.

2.

After removing the instrument from the well and from its protective barrel, unscrew the angle unit from the electronic timer, leaving the camera still attached to the angle unit.

3.

Remove the top of the developing tank and fill the reservoir with developing fluid. Fill to within 1/8” of top.

4.

Holding the tank base as still as possible, re-assemble the developing tank and rotate the base until it is located in the OPEN position indicated by a scribe line on the base as shown in the photograph. NOTE: When the tank base is in the fully OPEN or CLOSED position as marked, a spring detent and matching recess prevent the base from rotating.

5.

Hold the developing tank in your hand or set it upright on a table and insert the camera into the receiving chamber.

6.

Push the camera firmly into the chamber to depress knob and rotate camera until the scribe lines on camera and developing tank line up. At this point, the film disc will fall into the developing reservoir.

7.

Turn developing tank base until the scribe line indicates CLOSED. The camera can now be removed from the receiving chamber. (Note: The developing tank base is always turned to the CLOSED position before removing the camera from the receiving chamber.)

8.

Inspect knob to see if red line is visible as explained in step 6 of camera loading section. If the red line is not visible, the film disc did not transfer to the developing tank. Repeat steps 4 through 7. A malfunction in the unloading of the film disc is usually due to developer or gummy substances in the camera disc trap. If this is the case, the instrument should be properly cleaned.

9.

After the film disc has been deposited into the developing reservoir, it should remain for 4 minutes. (Note: It is not necessary to shake the developing tank.) If the developer is cold (68°F or 20°C), continue developing for 6 to 7 minutes. If the developer is very cold, continue developing for 10 minutes. Too short a developing time can ruin the picture, but too long a time will not harm it.

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10. After the film disc is developed, remove the top of the developing tank and remove the disc from the reservoir. As soon as possible, wash the film disc in clean water and allow to dry. Reading the Single Shot Disc When reading the low inclination picture, place the reader over the disc so the hairline of the reader passes exactly through both the centre dot and the intersection of the cross hairs of the plumb bob as recorded on the disc. The magnetic azimuth or bearing is read from the relationship of the reader hairline to the markings on the compass card. The inclination or deviation from vertical is read by counting the number of concentric circles from the centre to the intersection of the cross hairs of the plumb bob. Each concentric circle represents 1° of angle on a 20° angle unit. The third piece of directional information read from the disc is the tool face orientation. This is only of interest when the single shot is being used to orient downhole deflecting tools. The tool face line in the picture is the radial line extending from the centre of the disc to the outside of the disc. At the end of the radial line is a tool face indicator circle. The tool face reading is obtained by the relationship of the radial line to the scale on the reader. When reading the high inclination picture, the disc is oriented so that all alphanumerics are right side up and read from left to right. As before on the low inclination units, three pieces of information are obtained from the film disc. The inclination is read from the intersection of the horizontal line and the calibrated scales running vertically. The azimuth, or magnetic bearing, is read from the intersection of the vertical line and the compass card. The tool face line is the heavy black post extending from the outer edge of the film disc inwardly approximately 1/8”. The tool face, when using the single shot to orient downhole tools, is read from the relationship of the tool face post to the scale on the reader. Assembly Precautions When using assemblies there are certain areas of caution that should be practised. They are as follows: 1.

Inspect the protective barrel bore for any dirt or debris that could have been lodged in the bore. Inspect the barrel threads and “O” ring seats for any cuts. Wipe both these areas as clean as possible before make-up.

2.

Inspect the barrel plugs for cut “O” rings and damaged threads. Apply a small amount of grease to the threads and “O” rings before assembling them with barrel.

3.

Prior to going into the hole, make certain barrel plugs are made up tight.

Single Shot Running Gear There are two different running gear assemblies normally used in conjunction with the single shot. These are shown in the photographs. The first assembly is the standard bottom landing assembly. This assembly is for simple survey pictures of the hole direction and inclination. The single shot instrument is spring shocked and run inside the protective barrel with no concern for instrument orientation. The second assembly is the muleshoe assembly (UBHO) used when orienting downhole tools with the single shot. In this assembly the instrument is not only shock mounted within the barrel, but also oriented with respect to the downhole deflection tool. Reading of Single Shot Discs Refer to page 9 - Reading of Survey Discs as per Eastman Christensen.

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3

2 4

1

6 7

5

8

9

10

14 13

16

15

11

12

Item No. 1 2 3 4 5 6 7 7 7 7 7 7 7 7 8 9

Part No. Orienting

Description

Bottom Landing 561065 561048 561061 561069 561042 561016 561017 561018 561019 561043 561044 561045 551051 551046 561025 561080

Rope Socket Spear Point Over Shot Swivel Stabiliser Body Rubber Stabiliser Pin Spacer Bar 1' Long Spacer Bar 2' Long Spacer Bar 3' Long Spacer Bar 4' Long Spacer Bar 5' Long Spacer Bar 6' Long Sinker Bar 4' Long Sinker Bar 5' Long Barrel Plug Barrel "O" Ring

Item No. 10 11 12 13 14 15 16

Part No. Orienting

Description

Bottom Landing 561026 550658 551021

550966 561056 561081

Protective Barrel 6 1/2' Internal Shock Assembly Bottom Landing Assembly T-Bar Assembly Orienting Bar Assembly Mule Shoe Assembly Tell Tale Pin

910303 / 5

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SPERRY-SUN MAGNETIC SINGLE SHOT Operational Guide Using a Mechanical Circuit Breaker/Timer System Pre-Run Check Bulbs a)

Attach battery tube to single shot frame.

b)

Insert pre-checked batteries into tube with positive nipple down.

c)

Short exposed battery terminal to the case with an Allen key - the bulbs should illuminate.

Mechanical Timer a)

Pull out setting knob and set at zero (0).

b)

Connect to battery tube and bulbs should illuminate for 1 minute 45 seconds.

c)

Re-set timer to 2 minutes and check the interval until bulbs illuminate against surface watch.

Compass a)

Check compass face is clean.

b)

Check float for freedom of movement.

c)

Check for leaks, bubbles or other damage.

The instrument is now ready for assembly prior to loading with a photographic disc from a pre-checked supply. Where time permits, a sample survey should be taken on surface. 6” Compass 1.

Read from the centre of the compass card to the cross-hair centre to determine inclination. Example: 1-3/4°.

2.

Determine the hole direction of the chart as follows: Align the reference line of the reader so that it passes through the chart centre and crosshair centre. The hole direction will be along the reference line away from the chart centre and towards the crosshair. Example: S35W.

3.

Correct to TRUE/GRID North.

Running Procedure 1.

Check compass range, marked on side of compass unit, is sufficient to record expected inclination.

2.

Pull out timer setting knob and set sufficient time on clock to allow for loading disc into instrument, loading instrument into protective case and running tool to desired depth.

3.

Synchronise surface timer with instrument timer.

4.

Load photographic disc as follows: a)

Check arrows above brass knurled rotating section point to “OPEN” and visually check disc chamber is clear.

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LOADING, SETTING, TIMING AND OPERATION OF DROPPED SURVEY BARREL EQUIPMENT b)

Align disc magazine slot to instrument slot by use of magazine locator pin. Hold magazine tightly against frame to prevent premature disc exposure.

c)

Pull magazine plunger up and then smoothly push plunger down, thus forcing one disc into the disc chamber.

d)

Continue to hold magazine in position and turn brass knurled section until the arrow points to “LOADED”. Should it go to “EMPTY”, then no disc has been loaded.

5.

Remove bottom plug from protective case and partially insert instrument WITH TIMER UPPERMOST.

6.

Slot bottom spring onto compass base, push the whole assembly into the protective case and tighten the bottom plug.

7.

Position the tool in the drill pipe and “GO-DEVIL” into the non-magnetic drill collar.

8.

Although the drill string can be worked during the estimated “free-fall” period, it must be held for one minute prior to the survey being recorded.

9.

The disc will be exposed for approximately one minute and forty-five seconds after which the drill string can again be moved.

10. If the bit run is to continue, the tool can be retrieved by running an overshot on a wireline, to latch onto the spear point. Alternatively, the tool can be tripped to surface. 11. After removal from the protective case, position the instrument above the developing tank, with the tank slot and instrument slot held tightly together to prevent light entering. 12. Turn brass knurled section to “OPEN” to allow disc to drop onto tank. 13. Pull tank plunger and disc will fall into tank. Release plunger. 14. Before separating tank and instrument, turn the brass knurled section to “EMPTY” to confirm that the disc is in the tank. 15. Set developing tank on a flat surface and quickly pour in combination fixer/developer fluid until fluid overflows and leaks from side of developing tank. 16. Shake the tank to ensure all the disc is covered by the fluid and leave for four minutes. 17. Remove the disc from developing tank and wash both in fresh water. 18. Read film disc with reader provided and record survey. Store disc in envelope provided. 19. Replace instrument in carrying case after cleaning. NOTE: Compasses should be alternated to cross-check each other. For an inclination only survey in a standard steel collar, an inclinometer must be used in place of a compass. A thermal shield must be used at all temperatures approaching 230 deg F. The shield is capable of withstanding 600 deg F for five hours and requires the B-Type or slim hole instrumentation.

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SPERRY SUN SURVEY BARREL COMPONENTS MECHANICAL CIRCUIT BREAKER

35 MIN 50 MIN 95 MIN

MONEL SENSOR

_

ADAPTER

BATTERY CASE

BATTERY TUBE

+ MONEL SENSOR RECORD DISC HOLDER

ADAPTER SLEEVE

CONNECTOR TUBE

CAMERA ASSEMBLY

LENS AND LAMP HOLDER LAMP HOLDER BULB

COMPASS UNIT

COMPASS AND ANGLE UNITS

910303 / 6

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SURVEY BARREL

ELECTRONIC PROGRAMMER ASSEMBLY

PAA SPEARHEAD

SWITCH

EXTENSION BARS

SWIVEL

BATTERY TUBE

FINGER GUIDE FINGER GUIDE

SHOCK ABSORBER ELECTRONICS

RECORD DISC HOLDER

EXTENSION BAR

TIMER

TOP PLUG CONNECTOR TUBE

LENS AND LAMP HOLDER LAMP HOLDER

SINGLE SHOT INSTRUMENT PROTECTIVE CASE

COMPASS UNIT

INTERNAL SHOCK ABSORBER

INTERNAL SPRING

B-TYPE THERMAL SHIELD

BOTTOM BRASS PLUG

BOTTOM PLUG 910303 / 7

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SPERRY SUN - READING SURVEY DISCS

SPERRY SUN - READING SURVEY DISCS

8 7 6 5 4 2 3

2

5 6

7

8 W

3 4 1 2

1

1

2

1

5 6

1 7

2 6° COMPASS

1. Read from the centre of the compass card to the cross-hair centre to determine inclination. Example : 1-3/4° 2. Determine the hole direction of the chart as follows : Align the reference line of the reader so that it passes through the chart centre and crosshair centre. The hole direction will be along the reference line away from the chart centre and towards the crosshair. Example : S35W 3. Correct to TRUE / GRID North

910303 / 8

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TELECO INSTRUCTIONS FOR USING THE TELECO SINGLE SHOT KIT General Information The Teleco Single Shot is composed of the following basic sections: battery pack, timer, camera and angle unit. When assembled the instrument is water resistant to a depth of one metre, and is constructed of corrosion resistant materials. Assembly Information To assemble the instrument, proceed as follows: 1)

Load 3 type “C” cells into the battery pack, taking care to note the positive battery terminals are pointing to the end marked “+” on the battery pack.

2)

Screw the battery pack into the female end of the timer, and hand tighten.

3)

Screw the camera sleeve, with camera inserted, onto the available end of the timer unit.

4)

To test: Set the timing switches to 0-0 and press the RESET button, the lamps should come on, and the LED indicator flash on a 4 seconds on/4 seconds off cycle for 30 seconds (exposure time).

5)

Unscrew the camera from the camera sleeve (leaving the sleeve attached to the timer).

6)

Screw the camera onto the angle unit, and hand tighten.

7)

Place the film loader onto the camera body with the locating pin inserted into alignment hole above the film disc slot on the camera. The lever on the loader is then pulled out, and pushed back in thereby inserting a film disc into the exposure chamber. The loader is removed by allowing the spring tension to close the loading gate, and then pulling the loader away. When a film disc has been correctly loaded, a red band appears in the window opposite the film disc slot.

8)

The camera and angle unit are not screwed onto the camera sleeve, and hand tightened. THE SYSTEM IS NOW LOADED AND READY FOR TIMER SETTING.

9)

The timer may be set in one minute increments from 1 to 99. By looking at the timer with the reset button to the left, the switch on the left dictates delay in ten minute increments, and the switch on the right dictates the delay in one minute increments. The required timer delay is thus simply dialled in.

10) To activate the timer system the reset button is firmly pressed, and the sequence begun. To confirm the timer is counting down the red LED indicator will flash. The film will be exposed for a period of thirty seconds after the selected time has elapsed. The complete instrument is now ready for loading into the appropriate outer barrel assembly, and run in the hole. REMEMBER, TIMING CYCLE STARTS ON RELEASE OF THE RESET BUTTON. Running Gear The instrument is run inside conventional outer barrel assemblies as shown, and may be run on slickline or dropped and retrieved with an overshot.

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Unloading the Film Upon retrieval at surface, the single shot instrument is removed from the outer barrel and the film developed for reading as follows: 1)

Remove the camera assembly from the sleeve with the angle unit still attached.

2)

Fill the developing tank with developer/fixer and ensure that the locating pin on the tank mates with the alignment hole on the camera. Turn the lever on the tank to the open position, and slide the camera assembly to the rear, allowing the disc to drop into the tank.

3)

Turn the lever on the tank to the closed position and remove the camera assembly.

Check the indicator slot on the camera to ensure the red line has disappeared, and gently shake the developing tank whilst listening to verify the presence of the disc. Developing time should be between three to five minutes, depending on temperature (higher temperature - less time).

Note: Teleco survey barrel components are identical to Smith survey barrel components.

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SURVEY BARREL COMPONENTS 3 - "C" CELLS 7 6 5

3 2 1

2 1 0

9 8

0 9

X10

5 4

8 7 6

TIME

4 3

X1

ELECTRONIC TIMER

,, ,, ,,

SLEEVE

BATTERY PACK

,, ,, ,,

CAMERA

, ,, , ,,, ,,

,,, ,,, ,,,

ANGLE UNIT

READING SURVEY DISCS

0° - 12°

0° - 90°

8 12 3 4 5 6 7

0 1 2 3 E 4 1 8 7 2 56 5 4 3

N

5

2

5

5 6 7 8W8 7 6

4 32 1N1 2 3

4 32 1N1 2 3

4

76

3

5 6 7 8W8 7 6

4

5

4

4 2 3

E8

1 8 7 6 5 4 3 2

3

S1

0° - 5°

6 7 8

4

W

1

5

5

8 12 3 4 5 6 7

2

4 2 3

76

5

S

3

S1 E8

32 1

4

32 1

6 7 8

4

4 5

0 1 2 3 4 5 6 8 7 7

12° / 90°

0-5

DEGREE UNIT,

92 DEGREE AZIMUTH,

2.6 DEGREE INCLINATION

0-12

DEGREE UNIT,

50 DEGREE AZIMUTH,


0-90

DEGREE UNIT,

75 DEGREE AZIMUTH,


12-90 DEGREE UNIT,

46 DEGREE AZIMUTH,


910303 / 9

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LEAK-OFF TESTING

Casing Seat Leak-Off Tests (also called Formation Intake, Formation Strength, Pressure Integrity Tests, etc.) are carried out for the following reasons: a)

To investigate the strength of the cement bond around the casing shoe to ensure that no communication is established with higher strata in case pressures in excess of the mud hydrostatic head are encountered.

b)

To investigate the wellbore capability to withstand pressures below the casing shoe in order to allow proper well planning with regard to the setting depth of the next casing string. This is especially important when abnormal pressures are expected.

c)

To collect regional information on formation strength for optimisation of well design.

The following outline shall provide a Standard Test Procedure to be used by BP. This standard method is the continuous method, however the hesitation method is also included for cases when that is considered the better option. Limit tests are preferred unless the additional information gained from a full leak-off test is required for future well planning and casing designs. The continuous method is preferred over the hesitation method unless the test is carried out on a critical well such as when the mud weight in use is close to overburden.

1.2

The drilling programme will advise whether or not leak-off testing will be done to a leak-off value or to a specified limit.

1.3

Test Pressures Test pressure to be limited to a maximum pressure equivalent to whichever is the least of:a) b) c) d) e)

The casing test pressure. The well head test pressure. The BOP test pressure. 80% of casing burst pressure. A pressure advised in the Drilling Programme.

The BP Drilling Supervisor will be present whenever a Leak-Off Test or any wellbore integrity test is made. 1.4

It should be noted that information obtained from tests in straight holes is not applicable to deviated holes (and vice versa). It is also not always true that deeper formations have a higher mud holding capacity than shallower ones. If doubt about this exists, testing of the open hole can be undertaken from time to time, if advised in the Drilling Programme.

2.0

EQUIPMEMT

2.1

Gauges Mud gauges are not sufficiently accurate for these tests. Use large scale gauges of various ratings to cover the full range of the proposed test. Mount the gauges on a small bore manifold with needle valves to shut off as gauge pressure limit is reached. e.g. Mount 300, 600, 1200 psi gauge for a 20” casing seat test. Ensure a Chart pressure recorder records the test.

2.2

Pumps The mud pumps will not be used. The normal practice is to use the cement pumps.

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LEAK-OFF TESTING

3.0

CASING SEAT TEST PROCEDURES

3.1

Preparation

3.2

Section

1.

Prior to any leak-off test a casing pressure test is carried out which will be designed to be higher than the pressure applied in the formation leak-off test.

2.

The casing pressure test should be carried out at the same pump rate as that proposed for the leak-off test, and a graph should be plotted of volume pumped vs. pressure at a fixed, slow pump rate.

3.

When the formation leak-off test is performed the same graph paper should be used to plot the same parameters at the same pump rate as for the casing pressure test.

4.

As soon as the pressure deviates from the slope produced during the casing pressure test, it can be assumed that leak-off is starting and that pumping can stop.

Continuous Method 1.

Drill out cement plus 3 - 5m of formation.

2.

Circulate and condition mud.

3.

Pull up into the casing.

4.

Ensure the hole is full and close the BOP around the drillpipe.

5.

Pump mud slowly, at 0.25 bbl/min, using a high pressure low volume pump until the pressure builds up. Calibrated pressure gauges, covering various pressure ranges and preferably mounted on a special manifold, should be used. Mud gauges are not sufficiently accurate for these measurements. Rig pumps are unsuitable for carrying out leak-off tests.

6.

Plot the results of pressure vs. volume pumped on the same graph produced for the casing pressure test, taking readings every 0.25 bbl. The same slow pump rate should be used for the casing pressure test and the leak-off test.

7.

Continue until the pressure deviates from the straight line or until the limit value has been reached, whichever is the lower.

8.

Keep well closed in to verify that a constant pressure has indeed been obtained, continuing to record pressure vs. time on chart recorder.

9.

Bleed off pressure and measure volume returned to determine volume lost to the formation.

From the procedure outlined above, it can be seen that during a formation strength test the formation should not be fractured. The point on the pressure vs. volume plot which is characterised by a deviation between the final pump pressure and the static pump pressure after the waiting time is called the “Formation Intake Pressure”. This point normally coincides with the point where the pressure vs. volume plot departs from the approximate straight line relationship. 3.3

Hesitation Method 1.

Drill out cement plus 3m - 5m of formation.

2.

Circulate and condition mud.

3.

Pull up into the casing.

4.

Make sure the hole is full and close the BOP around the drillpipe.

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LEAK-OFF TESTING

5.

Pump mud slowly using a high pressure low volume pump until the pressure builds up. Calibrated pressure gauges, covering various pressure ranges and preferably mounted on a special manifold, should be used. Mud gauges are not accurate enough for these measurements. Rig pumps are unsuitable for carrying out leak-off tests.

6.

Pump maximum of 1/4 bbl/min in 1/4 bbl increments, wait for 2 minutes or the time required for the pressure to stabilise in case this takes longer as the test progresses.

7.

Note the cumulative mud volume pumped, the final pumping and final static pressure.

8.

Repeat items 6 and 7 and plot pressures versus cumulative mud volume for each pumped volume increment. Plot the results on the same graph used for the casing pressure test.

9.

Continue procedure until the final pump pressure deviates from final static pressure after the waiting time or until a predetermined pressure has been reached.

10. Keep well closed in to verify that a constant pressure has indeed been obtained. 11. Bleed off pressure and establish volume of mud lost to the formation. From the procedure outlined above it can be seen that during a formation strength test the formation should not be fractured. The point on the pressure versus volume plot which is characterised by a deviation between the final pump pressure and the static pressure after the waiting time is called the “Formaton Intake Pressure”. This point normally coincides with the point where the pressure versus volume plot departs from the approximate straight line relationship. 4.0

LEAK-OFF TEST PROFILES

4.1

Various types of pressure versus volume plots can be encountered, depending on the kind of formation being tested as shown in Figures 1 to 4 (page 5). Further pumping would fracture the rock until a stage is reached when the fracture propagates into the formation and a sharp pressure drop is observed on the surface. The pressure at which this occurs is the “Formation Breakdown Pressure”. Sometimes a maximum limit is set for the pumping pressure during a formation strength test. In those cases all that is recorded is a “maximum required mudholding capability” and the test is called a “limit test”.

4.2

Calculate the formation strength in equivalent maximum mud weight, as follows: Formation Strength (lb/gal)

=

P + MUD HYD D X 0.052

Where: P = Formation Leak-Off Pressure determined from Pressure vs volume plot. MUD HYD = Hydrostatic pressure of mud column in well (psi). D = True Vertical Depth (ft) from mean sea level to depth of leak-off test. 4.3

The formation intake pressure is dependent on the type of formation (strength, permeability, etc.), mud properties as well as on local geology. Brittle rocks fracture normally after limited deformation and suffer from a considerable permanent reduction of borehole mud holding capability after fracturing. For such, normally strong formations, a limit test is often sufficient to plan the further well programme. The application of a full leak-off test is not recommended under those circumstances. In non-consolidated, plastic, loose or highly permeable formations very low pressures cause loss of liquid. The final pumping pressure will always be higher than the final static pressure and the formation intake pressure can only be established approximately from the pressure versus volume plot shown in

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LEAK-OFF TESTING

Fig. 1. Normally this information will suffice, since it is well known that the formation is weak and the main purpose of the test is to establish the absence of communication around the casing. Prior to pumping, the Drilling Supervisor should mark his pressure/volume pumped plot at a number of various formation strengths. He can then ensure his plot is realistic. 4.4

It is not necessarily correct that deeper formations can support more hydrostatic pressure than shallower ones. However, under no circumstances will another leak-off test be made without specific instructions from Base.

4.5

Page 6 illustrates the Standard format which will be used to record the leak-off test.

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LEAK-OFF TESTING

LEAK-OFF TESTS - SCHEMATIC REPRESENTATION

UNCONSOLIDATED PLASTIC FORMATION

CONSOLIDATED PERMEABLE FORMATION

1

PRESSURE

PRESSURE

1

CUMULATIVE VOLUME

CUMULATIVE VOLUME

Figure 1

Figure 2

CONSOLIDATED FORMATIONS LOW OR IMPERMEABLE

CONSOLIDATED FORMATIONS "LIMIT TEST" DESIRED TEST PRESSURE PRESSURE

PRESSURE

1

CUMULATIVE VOLUME Figure 3

"LIMIT TEST"

CUMULATIVE VOLUME Figure 4

FINAL PUMP PRESSURE AFTER EACH INCREMENT FINAL PRESSURE AFTER WAITING PERIOD 1

FORMATION INTAKE PRESSURE

2179 / 41

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LEAK-OFF TESTING

FORMATION LEAK OFF TEST WELL:

TESTED BELOW

CASING SHOE DEPTH:

MD

TVD

RIG:

HOLE DEPTH:

MD

TVD

DATE:

VIS

P.V.

Y.P.

MUD WEIGHT:

" CASING SHOE

GELS

FLUID PUMPED / RETURNED:

SURFACE PRESSURE (PSI)

FORMATION IN OPEN HOLE:

BARRELS PUMPED

FORMATION STRENGTH:

PSI

EQUIVALENT MUD WT:

REMARKS:

SUPERVISED BY: 2179 / 40

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CORING

1.

GENERAL

1.1

The barrel type used by BP varies. Though the general configurations are all similar it is essential the Drilling Supervisor ensures he has the manufacturers hand book available for reference.

2.

CORING CONSIDERATIONS AND PRE-CORE OPERATIONS

2.1

There are occasions when the coring penetration rate is higher than the drilling rate, however, this is rare. Coring operations will only proceed when, in the opinion of the BP Drilling Supervisor, the hole conditions are suitable. Hole conditions are all important since the core barrel will: a)

Normally penetrate slower than drilling.

b)

Be of large diameter relative to the hole size.

c)

Only allow a circulation rate often less than that used when drilling, especially when rat hole coring. Typical circulation rates used for normally consolidated formations are: 12 1/4” hole 8 1/2” hole 6” hole

+/- 550 gpm +/- 300 gpm +/- 150 gpm

Circulation rates for unconsolidated formations are reduced to minimise core washing: 12 1/4” hole 8 1/2” hole

260 - 300 gpm 150 - 200 gpm

Note: If the reservoir is prone to washing out, restricted circulation rates may be required. d)

Be easier to plug with LCM.

e)

Have a corehead that is easily damaged with: i) ii)

Junk. Having to ream undergauge sections of hole.

Note: Extreme care must be taken when tripping with a core barrel. 2.2

With a reduced penetration rate there are four main areas of concern: a)

Casing Wear: in deviated wells the effective side loads should be calculated in order to optimise drillpipe protector placement. If side loads are a problem, consider the possible use of a motor for coring. Check the DP hard facing. Increase the number of casing protectors, especially at any dog legs or through a build-up section.

2.3

b)

Differential Sticking: as the DC assembly may be relatively stationary the risk of differential sticking is increased. The length of DC’s run should be minimised and stabilisers installed across any exposed sands.

c)

A Key Seat may be created. When pulling the barrel ensure that the driller minimises overpulls and open hole pulling speeds.

Ensure that prior to pulling out of the hole to run the core barrel, the mud is conditioned. Mud cake thickness and water loss levels should be minimised.

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CORING

Note the type of solids/cuttings coming from the hole, if cavings are present in the returns, action will have to be taken to cure the caving formation BEFORE the last bit is pulled. If the string overpulls when pulling the last bit, go back to bottom: check trip until hole is clean. 2.4

With full hole cores, the reduction of circulating rate will normally not be a problem as the reduction in flowrate is generally balanced by the reduction in volume of cuttings generated. However, where a rat hole core, i.e. 8 1/2” in a 12 1/4” hole, is being taken ensure the mud properties are capable of adequate hole cleaning at the reduced circulation rate. If a caving or sloughing hole problem exists, the coring operation may have to be aborted or the core barrel size reviewed at the planning stage: ensure a hole size corehead and large barrel is used.

2.5

Ensure losses are fully cured before any coring operation is undertaken. If losses develop whilst coring, stop immediately. Prior to mixing LCM pills be fully aware of the additional restrictions within a core barrel. Consideration should be given to installing a circulating sub in the coring assembly as contingency against well control problems. Opening ball diameters to be checked.

2.6

a)

Where the coring depth is known approximately, a junk sub should be considered for the last bit run in the hole. A DP wiper rubber must be used on the bit trip out of the hole. Also use the DP wiper rubber on the trip in the hole with the core barrel. The wiper rubber is intended to prevent junk falling down the hole. Review the previous bit runs to see if broken teeth indicate possible junk in hole or if inserts have been lost. If this is the case consider making a separate trip with a hard bit and junk sub and clean up the bottom of the hole. Whenever the junk sub run is made, ensure that prior to running the core barrel the junk recovered is checked. Dependent upon recovery it may be necessary to make an additional junk sub run prior to coring.

b)

Check the last bit prior to coring for gauge size. This is important for: i)

Preventing damage to full gauge core heads when running back in the hole.

ii)

Ensuring the stabilised assembly does not get stuck whilst running in, or give torque problems when coring.

Whenever reaming is undertaken with a corehead and barrel, always maximise the circulation rate and minimise rotary RPM and WOB to prevent gauge diamonds being damaged. For anything other than minimal resistance when reaming, pull the core barrel and check trip the hole. 2.7

Ensure the drill string and DC assembly is drifted, at least to the TOTCO ring. Retrieving the TOTCO instrument at the casing shoe on the trip out of the hole will act as a good drift run.

2.8

Check: a)

Fishing tools are available for all ODs and IDs.

b)

The core barrel make-up torques, they are generally of a low value. (Use a chain tong for the initial make-up of threaded connections on the core barrel.)

c)

The bearing assembly.

d)

The inner barrel condition, i.e. it is straight and has minimal corrosion. The inner barrel connections should be made up with a chain tong.

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CORING

Note: When fibreglass inner barrels are being used, ensure that the ID is slick where the tube is bonded to the coupling. Upsets are not acceptable. e)

The inner barrel space out distance is correct.

f)

The core head condition: Water ways clear and diamonds unburnt. The correct bit breaker is available, and fits.

2.9

g)

The barrel stabilisers are the correct gauge.

h)

The ball seat condition and ball size.

i)

The safety joint is clean and properly lubricated. All “O” rings should be replaced if not in good condition.

Always trip with a wiper rubber on the string. Ensure it is of large enough diameter that it cannot be carried through the bell nipple and BOP when RIH. Ensure the rubber is removed prior to reaming or coring.

2.10

Stabilisation at and above the barrel is of the utmost importance. If the barrel design has no top stabiliser install a string stabiliser immediately above. Run stabilisers a minimum of 9m and 30m in the DCs above the barrel’s top stabiliser. This will help minimise the risk of differential sticking. a)

For an 8 1/2” rat hole core with 9m barrel in 12 1/4” hole: Core Head - Barrel Stab - Barrel - Barrel Stab - Safety Stab - 12 1/4” String Stab - 1 x 8” DC 12 1/4” ST Stab - 2 x 8” DC - 12 1/4” Stab. Add 8 1/2” Stabs and 6 1/2” DC as the rat hole deepens.

b)

For 8 1/2” core in 8 1/2” hole: Core Head - Barrel Stab - Barrel - Barrel/String Stab - 1 x 6 1/2” DC - 8 1/2” Stab - 2 x 6 1/2” DC 8 1/2” Stab.

Note: Consideration should be given to running a circulating sub directly above the core barrel as a contingency if packing off occurs. Ensure that the core barrel ball can pass through the circulating sub. 2.11

Always minimise the DC assembly length for the WOB required by the core head. Replace DC with HWDP where possible in 12 1/4” and 8 1/2” holes.

2.12

Always run jars in the assembly. Ensure that the core barrel ball, or dart if a rubber sleeve barrel is being used, passes through the jar.

2.13

Where a rubber sleeve core barrel is being used, check the assembly immediately above the barrel has a bore large enough to accept the rise of the inner barrel.

2.14

Run in the open hole slowly and ensure the driller watches for hole resistance.

2.15

Check the space out of the string is such that when on bottom the maximum kelly length is above the rotary, thereby ensuring the maximum continuous coring prior to making a connection. Ensure that pup joints will not be across the BOP stack during coring operations.

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CORING

UNCONSOLIDATED CORING 1.

The coring operation must be planned to achieve the maximum possible core recovery. With unconsolidated sand and fractured limestone, there are additional problems with recovery in addition to core jamming. The core may be washed out by circulation or be lost on the trip out of the hole. Equipment used to improve core recovery include: a)

Fibreglass inner barrels. These barrels are cut into metre long sections and capped without extrusion of the core. Fibreglass has a lower coefficient of friction than steel and should allow easier core entry. The fibreglass quality should be checked prior to make-up of the inner barrel. Check the OD of the barrel as undersized fibreglass has been known to collapse. Check that the IDs of the couplingsare flush with the ID of the fibreglass as small upsets may cause jamming. Check the fibreglass for evidence of fraying. On recovery of the core at surface, each section of fibreglass should be removed from the drill floor in a rigid cradle. Every effort must be taken to move the core without bending it. The saw to cut the fibreglass will be provided by the coring company. Ensure that adequate safety equipment is provided.

b)

A variety of catcher assemblies are available: i) ii) iii)

Spring type. Slip and dog type. Gravity actuated flapper type.

The choice will depend on the expected degree of consolidation of the sand combined with area experience.

2.

4.

c)

Face discharge coreheads which reduce the possibility of the core being washed away at the corehead. The use of extended pilot shoes reduces the area of core subject to washing out inside the corehead.

d)

Frozen cores.

Rathole coring of unconsolidated sand should be avoided as the increased barrel instability (at least on the first core) can lead to loss of recovery. As the coring rate is expected to be high, there is normally no reason to rathole core.

CORING OPERATIONS 1.

Make up the coring assembly and RIH slowly. Beware of hole resistance.

2.

Wash down the last 10 - 15m to bottom. Tag the bottom of the hole gently with high circulation rate.

Note: Ensure Drilling Chart Recorder is engaged and working. 3.

Wash the bottom of the hole without rotating and at a high circulation rate. Record the drags in the hole.

4.

When circulation is complete (min. 1/2 hour) pull back to install the ball.

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CORING

If required, pump a small heavy pill into the string to prevent back flow. Back flow makes it difficult to confirm the ball has actually gone into the string. 5.

Re-install the kelly, pump slowly, run in and gently tag the bottom of the hole. Pick up a minimum distance off bottom. Whilst waiting for the ball to reach the seat: a) b) c)

Check circulation rate. Check circulation pressure. Check the probable pressure increase when the ball seats.

Prior to the ball seating slow down the pump. 6.

When the ball seats: a)

Start the rotary, record the off bottom pressure. Take SCR’s.

b)

Tag bottom and add the recommended starting weight.

c)

Continue with this weight.

d)

i)

With a hole size corehead until at least one foot is cored.

ii)

With a rat hole core until at least half the first of the barrel’s stabilisers is in the cored hole.

Add weight and RPM up to: i) ii)

e)

7.

The maximum recommended for the corehead. or When the penetration rate ceases to increase.

Continue with constant weight on bit, RPM, and circulation rate. Constantly record the pump pressure and rotary torque. Watch carefully for any indication of rough drilling or drill string harmonics. Attempt throughout to ensure smooth rotation and addition of weight.

Constant pump output is very important, a pump pressure change should be noticed immediately. Common problems when coring: a)

b)

Pressure increase which may be caused by: 1.

Plugging of the barrel. Stop rotating, lift off bottom and compare pressure with the initially recorded off bottom pressure. The barrel must be pulled out of the hole.

2.

“O” ringing of the corehead, or plugging of the water passages. This will normally be accompanied by a decrease in penetration rate. If the situation does not quickly revert to normal, the core head will be seriously damaged.

3.

Change of formation.

Core Jamming: This will normally give a decrease in pump pressure and penetration rate, with a change in torque readings. The barrel will have to be pulled.

8.

When making a connection or pulling off bottom, stop rotation and circulation and pick up slowly. On occasions, overpull will be seen as the core catcher grips the core. Pull to a maximum of

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CORING

20,000 lbs overpull, after allowing for drags. If the core fails to break, start circulating up to the maximum used while coring and hold the overpull until the core breaks. Pick up 3m then lower to within 0.5m off bottom. Resistance may indicate the core has been left in the hole. Pick up and make the connection or POH.

Note: Do not use the rotary for the connection, but back out the kelly. After a connection, when coring is to resume, tag bottom gently. Without rotating, add weight to the core head to approximately 50% greater than the coring weight. This will release the core from the catcher. Pull back to a light coring weight, start the pump and begin rotating slowly. Do not use the full coring weight until at least 6” has been cored. Continue coring. 9.

Circulate bottoms up.

Note: If cutting an unconsolidated core, this should be avoided. Circulate bottoms up prior to cutting the core. 10. POH.

Note: Do not rotate and attempt at all times to minimise jarring or shock loads. Instruct the Driller to set the slips carefully. 11. Remove the core head, install the protector and then recover the core from the inner barrel. 12. If the barrel is to be re-used, repeat all checks. If it is to be laid down, ensure all stabiliser connections are broken and the barrel is flushed through in the Vee Door. AT ALL TIMES when handling a core barrel, use the DC clamp. 13. When rat hole coring, do not have more than 40m of rat hole. i.e. Clean out with full gauge bit before proceeding with cutting the next core. 14. During coring operations involving the possible presence of H2S, only essential personnel should be on the drill floor wearing BA apparatus. The BA apparatus must be worn until such time that gas testing indicates that the area can be declared safe.

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ORIENTED CORING

GENERAL 1.

Oriented cores are obtained by simple modifications to a standard core barrel. a)

The core catcher is replaced by a scribe shoe at the base of the inner barrel.

b)

The ball catcher is replaced by a mule shoe at the top of the inner barrel.

The scribe shoe scores the core with three knives as it enters the inner barrel. One scribe knife is identified as the “Reference Knife” and it is to this that all survey data is referred. The mule shoe acts as a UBHO sub for two survey probes positively locked in tandem into the mule shoe. The tool face is mechanically aligned to a reference on the mule shoe. The offset between the reference on the mule shoe and the reference knife is measured and survey data subsequently corrected for it. The core can be cut continuously without the requirement to stop at survey stations. Two systems are currently available for oriented coring. Their differences are listed below: Type 1: e.g. Diamant Boart. a)

A non-magnetic inner barrel is run at the top of the assembly to house the probes which are protected from mechanical and hydraulic disturbances.

b)

A ball is dropped to divert the flow to between the inner and outer barrels.

c)

The probes can only be inserted at surface and cannot be retrieved by slickline.

Type 2: e.g. Oreco.

2. 2.

a)

The probes are housed in a non-magnetic drill collar above the core barrel.

b)

The probes act as a ball diverting flow between the inner and outer barrels and are normally inserted on surface.

c)

The probes can be soft landed when the barrel is on bottom if full bore circulation is required whilst running in.

d)

The probes can be retrieved using an overshot if required.

A fibreglass inner barrel can be used if required.

PRE-JOB CHECKS 1.

Identify the main knife and centre punch its position on the mule shoe assembly (if necessary).

2.

Install and tighten the mule shoe sub and centre punch.

3.

Check the landing ring is in place.

4.

Check the stinger is in good condition (including the threads).

5.

Check the overshot latching fingers are in good condition.

6.

Check that all handling tools are in good condition.

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ORIENTED CORING

Check that the probe battery type is suitable for the depth and temperature of the interval to be cored. If EMS probes are to be used, there are 3 types of suitable batteries: a)

Alkali batteries which last 20 hours and can be used in temperatures up to 180°F.

b)

Silver Oxide batteries which last 30 hours and can be used if temperatures exceed 180°F.

c)

Lithium batteries which last 40 hours and can be used in temperatures greater than 180°F.

Note: Lithium batteries can only be transported by boat. Adequate stocks must be available prior to the job. If the ESS probes are to be used, only lithium and alkali batteries are suitable.

Note: Most oriented coring is undertaken using EMS methods. 8.

Check the length of the probe assembly. Normally, two EMS probes will be run in tandem spaced out to locate the sensors either in the middle of the non-magnetic core barrel or +/- 3m and 6m above the pin end of the lower nonmagnetic drill collar. 1 1/4” spacer bars will be used (1 3/4” spacer bars have been known to erode).

Note: The probes must be positioned out of magnetic interference from the previous casing shoe and drill string. This is currently 18m below the casing shoe and 7m above, or 12m below, magnetic material in the drill string. 9.

Check that the probes, retrieving overshot and ball (if used) can pass through the circulating sub and jars.

10. Use the survey interval requirement, expected ROP and trip time to set the timer on the probes. The EMS probe can take 1500 shots per probe and the ESS probe 2000 shots. 3.

MAKE-UP OF THE ORIENTED CORE BARREL Prior to making up the core barrel the sighting bar must be aligned with respect to the key slot in the mule shoe. The make up is as follows. 1.

Make up the mule shoe stinger onto the required length of aluminium extension bars. Engage into mule shoe. Attach the clamp and sighting bar such that it is aligned with the key slot in the mule shoe. See Figure 1.

The make up of the core barrel is as per standard instructions in Section 7200/GEN, including the following steps. 2.

Install the scribe shoe at the bottom of the inner barrel. See Figure 2.

3.

Make up all inner barrel connections. Punch marks are to be made across all connections to give any indication of tightening during coring.

4.

Replace ball seat with mule shoe/mule shoe adaptor.

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ORIENTED CORING

Once inner barrel has been made up on the bearing section, the misalignment between the reference knife and the EMS tool can be measured. 5.

Insert mule shoe stinger assembly into upper end of the inner barrel. Ensure that the stinger is positively engaged in the mule shoe.

6.

Attach pipe protractor and telescope of the scribe shoe. Zero with respect to the reference knife (Denoted by the groove scored on theoutside of the shoe). See Figure 3.

7.

Measure and record the misalignment of the sighting bar from the reference knife.

Note: Always quote results as if viewed from upper to lower end of the core barrel. Ensure survey hand is present. 8.

If the core barrel is not to be run with the EMS in place, retrieve the probe.

9.

Make up the safety joint connection.

10. Pull the core barrel and make a visual inspection of the assembly. If no non-magnetic inner core barrel is being run, the coring assembly should comply with Figure 4. 4.

RUNNING PROCEDURE 1.

If a non-magnetic core barrel is not in use, the non-magnetic BHA will consist of: Corehead - Core Barrel - 3m NMDC - NMS/Stab - 2 x 9m NMDC - SS/Stab.

2.

Run the core barrel assembly to depth. Wash last 10m with high circulation rate. Tag bottom and record drags. Commence circulation.

3.

If the EMS instrument is not run in the core barrel, drop the probe and pump down.

4.

Carry out an 8 station orientation shot prior to starting the core.

5.

Check circulation rates, off bottom pressure and cut the core. The core need not be interrupted to obtain survey data.

6.

If a connection is made, note the depth.

7.

At the end of the core section, the core barrel will be held stationery on bottom for two minutes, while still circulating, to provide a stationary record of the core orientation.

Points to Note 1.

The inner barrel must be made up correctly. The punch marks will indicate any tightening. If the inner barrel is not tight, then spiralling of the scribe lines will occur.

2.

Ensure the bearings are sound. Old bearings will cause spiralling of the scribe lines.

3.

The EMS tool replaces the usual ball. When the EMS tool is seated in the mule shoe it will divert the mud between the inner and outer barrels.

4.

As the core is being cut ensure that the drilling parameters are kept constant. This will help produce a clean core.

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ORIENTED CORING

It is important to note depths at which a connection is made, or if coring is stopped. This may help explain the sudden jump in the scribe lines.

SURVEY REQUIREMENTS FOR ORIENTED CORING The EMS 8 station orientation survey (rotational survey) taken at the start of every core provides a quality control parameter to confirm the accuracy of the survey instruments. There are two cases to determine whether the rotational shots are sufficient to obtain hole inclination and direction over the cored interval. 1.

When the coring point is within 70m of the previous casing shoe, or last defined survey point, providing the rotational surveys are confirmed, then they can be used to extrapolate over the cored section.

2.

When the coring point is greater than 70m from the last casing shoe or the well is deviated, it is then required to conduct a definitive survey to, or over, the cored section. Then either the definitive survey or rotational surveys can be used over the cored interval.

The definitive survey can be conducted in three ways. The survey is taken either when coring point is reached on the last bit run, on a wiper trip once coring has been completed, or on the last core run using the remaining battery life/memory capacity of the EMS tool. The decision as to which method to adopt will be made just prior to the coring job by the Supervising Engineer. 6.

TOOL FACE MEASUREMENTS FOR VERTICAL AND DEVIATED WELLS The objective in core orientation surveying is to determine the three-dimensional direction of the line joining the core axis and the scribe line, in a plane perpendicular to the borehole direction. In near vertical wells where the inclination is less than 5°, this is best visualised as a magnetic toolface, since in vertical hole gravity toolface is indeterminate. Over 5°, the orientation of the scribe line is best visualised as a gravity toolface vector. Tool face measurements may be expressed with reference to either Earth’s Magnetic Field or Gravity. As the inclination of the hole varies the emphasis on which effect is dominant, changes. Table 1 summarises the dominating influence on tool face readings as the inclination of the well bore varies, and also sets surveying guidelines. The decision on how the survey data will be obtained will be made by the Supervising Engineer prior to the coring job.

Well Inc.

Inc. 5°

5° Inc. 15°

Determination of scribe line direction.

Magnetic high side readings should be used for scribe line directional calculation.

Gravitational highside readings should be used for scribe line direction calculations.

Determination of borehole.

Borehole direcction from instrument used during core orientation.

Magnetic surveys whilst coring unreliable if close spacing. Obtain borehole direction from an independent survey.

Survey guideline.

Magnetic spacing for borehole direction not critical. Monels and spacer bars required as per Section 1.2.

Independent survey to borehole direction required. Magnetic spacing requirements will be advised by the Supervising Engineer.

Magnetic spacing for borehole direction is critical.

Inc. 15°

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ORIENTED CORING

RECOVERING THE ORIENTED CORE 1.

Once coring is completed and bottoms up has been circulated, POH. Replace the corehead with a protector.

2.

RIH and break out the safety joint. Clamp the inner barrel and retrieve the survey probes with the slickline overshot.

3.

Lock the travelling block and attach the bearing assembly clamp.

4.

Pull the inner barrel. Mount the protractor on the outer barrel and align the zero with the primary knife.

5.

Run in the inner barrel and check the offset at the mule shoe reference marker. If the offset has changed, record the reading and check for incorrectly torqued joints. Apply the necessary correction to the survey data.

6.

Pull the inner barrel to remove the protractor.

7.

Run in with the inner barrel. Remove the bearing clamp and proceed with the core recovery as normal.

8.

Before running the barrel again, check the following: a)

The bearings for free movement. Old bearings will cause spiralling of the scribe lines.

b)

Clarity of the scribe lines on the core. The scribe shoe may need to be replaced.

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ORIENTED CORING FIGURE 1 SCRIBE SHOE

INDICATOR STICK & CLAMP

90 o SPACER BARS

MULE SHOE STINGER

6'

MULE SHOE

FIGURE 2

90 o

SCRIBE SHOE 135 o

135 o

REFERENCE KNIFE

2179/42

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ORIENTED CORING FIGURE 3 TYPE PROTRACTOR AND TELESCOPE ATTACHED TO SCRIBE SHOE

REFERENCE SCRIBE KNIFE SCRIBE SHOE

0

PROTRACTOR

2179/43

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ORIENTED CORING FIGURE 4

CORE BARREL

ELECTRONIC MULTISHOT TOOL SPEARHEAD FIN GUIDE

MONEL LOCATION OF SURVEY INSTRUMENT

12" PROTECTIVE CASE 1 3/4" OD

MULE SHOE ASSEMBLY INNER BARREL BEARING

ADJUSTABLE "T" SLOT BRASS CROSS COVER

INNER BARREL

12' PROTECTIVE CASE 1 3/4" OD

30' CORE BARREL ADJUSTABLE "T" SLOT

NON MAGNETIC EXTENSION BARS 1 3/4"

30' CORE BARREL

SCRIBE SHOE COREHEAD

MILD STEEL EXTENSION ( FOR MUDFLOW AROUND BEARING SECTION ) 1 3/8"

KNIFE POSITION

MULE SHOE STINGER

2179/44

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EXTRA LONG CORE BARREL

1.

Where hole conditions dictate, it can be advantageous to run barrels longer than the standard 18m and 28m lengths, such that more time is spent on bottom coring and less time tripping, thus making the coring operation more efficient.

2.

PROCEDURE FOR MAKING UP AND SPACING OUT EXTRA LONG CORE BARREL

2.1

Make up the core head to barrel and make up the required number of sections of inner and outer barrels in the same way as for a standard barrel. Do not over torque inner barrels.

2.2

Pick up top section of barrel, ensure all the spacer shims are removed. Make up top section to the core barrel.

2.3

RIH to safety joint.

2.4

Back out safety joint, remake joint using chain tong to feel the make up of the safety joint faces.

2.5

Back out safety joint and install all the spacer shims. Use of an adjustable safety joint facilitates easier and quicker spaceout.

2.6

Carefully make up safety joint to feel when the core catcher bottoms out on the core head. At this point measure the gap between the safety joint faces. Repeat operation to double check the gap.

2.7

Back out the safety joint, work out the thickness of spacers that have to be removed to give a gap of 1/2” - 5/8” between catcher and core head, when safety joint is fully made up.

2.8

With appropriate spacers removed, make up the safety joint ensuring that it feels free with no premature bottoming out.

2.9

Make up the remainder of BHA and RIH.

Note: The number of DC’s required for the BHA is dependent upon the length of core barrel used. When running long barrels take into account the core barrel weight thus significantly reducing the DC requirement. BHA for 100m core barrel. 8 1/2” core head, 11 x 7” core barrel, XO, 3 x 6 1/4” DC, jar, 5 x 6 1/4” DC, XO, 15 HWDP. 3.

PROCEDURE FOR RECOVERING CORE FROM BARREL

3.1

With core barrel in slips, MU lifting sub and break out safety joint.

3.2

Pull back inner barrel 27m.

3.3

Install DC clamp around inner barrel.

3.4

Break inner barrel connection. Back out but do not lift out threads.

3.5

Install core tong on 27m inner barrel.

3.6

PU and part inner barrels slowly, ready to catch core. (It may be necessary to break core initially with hammer).

3.7

Recover first 27m of core.

3.8

Recover rabbit.

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3.9

Install rabbit in top of next section of inner barrel in RT.

3.10

MU inner barrels again. Remove DC clamp from inner barrel.

3.11

Run complete inner barrel into outer barrel in slips.

3.12

MU safety joint to outer barrel.

3.13

Pull back entire core barrel to 3rd stab. Install DC clamp around outer barrel below stab.

3.14

Break outer barrel above stab.

3.15

PU top 27m of outer and inner barrels 1m to expose inner barrel connection.

3.16

Install DC clamp around inner barrel.

3.17

Break inner barrel and back out. PU top 27m of complete core barrel.

3.18

Install protector to bottom of outer barrel. Rack top 27m of inner and outer barrel in derrick.

3.19

Install lifting sub on inner barrel in RT.

3.20

Remove DC clamp from inner barrel in RT.

3.21

Repeat procedure for remaining sections of core barrel.

3.22

Remove core catcher from bottom of inner barrel.

3.23

Recover last section of core and recover rabbit.

3.24

If coring is to be continued, check condition of core catcher and sub. Replace if necessary. Make up to inner barrel and run inner barrel into outer barrel.

3.25

Pull outer barrel back and inspect core head. Replace if necessary.

3.26

RIH core barrel, making up and spacing out as previously described.

4.

CORE BARREL SPECIFICATIONS - ORECO 7” x 4 3/8” Material Specification

Dimensions

-

- Outer Barrel AISI 4142 CD HT Inner Barrel AISI 4130 CD HT

Stabiliser 8 7/16” DC with 7” body C/B Outer 7” OD, 5 3/4” ID C/B Inner 5 1/4” OD, 4 1/2” ID Core Size 4 3/8” OD Max pull - outer barrel 640,000 lb Max pull - inner barrel 383,000 lb

Recommended Make Up Torque Outer Inner

-

12,000 ft lb 4,200 ft lb

BP EXPLORATION



Core Barrel Specifications - DBS 6 3/4” x 4” Material Specification - Outer Barrel AISI 4140/4142 Dimensions -

C/B Outer 6 3/4” OD, 5 3/8” ID C/B Inner 4 3/4” OD, 4 1/4” ID Core Size 4” OD Max pull - outer barrel 400,000 lb

Recommended Make Up Torque Outer - 26,000 ft lb

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MUD LOGGING SERVICES

1.

REPORTING

1.1

The logger reports to the Drilling Representative when he arrives on the rig and during rig up of unit. During operation, the logger must report all pit gains/losses, significant gas peaks and drill breaks to driller and operator representative. Geological information is reported to geologist, or the drilling supervisor in his absence. Charts in the unit should be properly annotated for times and events.

1.2

Equipment Monitoring and Unit Duties

1.2.1

The logging unit is an overpressured, skid mounted unit certified to the certifying authority and DOE requirements.

1.2.2

The external sensors are explosion proof and the unit equipment is protected by an intrinsically safe barrier system.

1.2.3

The unit is manned 24 hours a day or when required and the instruments should be monitored continuously.

1.2.4

Continuous Total Gas Detector records continuously on a strip chart and computer. The gas level alarm should be set to sound for significant gas increases and these should be reported. The chromatograph provides gas sample information only. Of paramount importance is H2S detection, also with operator-set alarms.

1.2.5

ROP Recorder is monitored continuously on a chart/computer for drill breaks, in addition to ROP data for mud log. Breaks should be reported in accordance with BP procedure for flow checks.

1.2.6

Pump Stroke Counter and Totaliser is used for calculated sample up times. The logger may also be told to count strokes during particular rig operations, e.g. displacing cement. Zeroing of cumulative strokes should precede any such operation.

1.2.7

Mud Pit Level Indicator. The active pit level must be monitored continuously by the logger and any changes reported. All pits in the system are monitored and printouts/computer records of total pits and active pits are kept. The audible alarm must be set within high and low limits acceptable to BP Drilling Representative.

1.2.8

Monitoring total gas, ROP and mud level are important for rig safety. The loggers primary job function is to collect and process samples, monitor the well for safety and acquire good quality data. Equally important is that alarms provided are set correctly and acknowledged. Failure to monitor pit gains/losses, drill breaks, or significant gas peaks can endanger the rig and crew. Failure to monitor other instruments can result in incorrect geological or drilling data. The consequence of lack of communication between logger, mud engineer or rig crew can be risk to the operation and loss of credibility in the mud logging service.

1.2.9

It is customary for any service company representative to discuss general aspects of the operation from time to time and should be readily available to do this.

1.3

Rig Up

1.3.1

The mud logging service will be considered ready when: i)

All equipment is rigged up, checked and calibrated.

ii)

Unit organised and ready for sample catching, bags are marked and log sheets prepared.

iii) Unit properly stocked with expendable supplies and spares. iv) The sensor hook-up verification sheet has been signed by the rig representative.

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The service will be considered complete when: i)

The well is finished and plugs are set.

ii)

The logs are completed and handed to operator.

iii) All data including worksheets, print-outs and data tapes have been handed to operator. Data tape format should be of the format described in the BP Technical Specification for mud logging services. iv) All equipment has been rigged down and packed for dispatch. 2.

CUTTINGS PROCESSING

2.1

Collection The sample is collected from a board in front of the shakers. The board is to be cleared after each sample. The sample is to be taken from the full width of the shakers so as to be representative of the interval. Be aware of finer particles from the formation not being screened out by the shakers, thus missing the sampling. In these cases, the desilter and desander should be sampled for visual examination only.

2.2

Washing Washed samples should be prepared in the unit washed with diesel (base oil if OBM) followed by detergent, potable or drill water. Removal of clay smear is important for cuttings description but may not be possible in soft clay formation. Samples are usually worked from coarse collecting sieve into fine sieve.

2.3

Description Lithologic analysis of cuttings is performed on washed sample in watch glass with the aid of a microscope and fluoroscopic analysis is carried out with the aid of solvents to detect hydrocarbons.

2.4

Drying and Logging Washed samples are dried in drying oven and packed in envelopes. Wet unworked samples are put into cloth bags directly at shakers. Samples for geochemical analysis are packed in barrier (SEET) foil bags with added bacteriocide (not aluminium tins).

2.5

The contractors personnel are responsible for ensuring samples are caught and packed at correct intervals and despatched to shore.

3.

INFORMATION REGARDING LIMITATIONS, ACCURACY AND TOLERANCES OF EQUIPMENT SYSTEMS AND PROCEDURES - BASIC MUD LOGGING

3.1

The Unit Equipment

3.1.1

Standard Equipment:

Computerised monitoring/acquisition of: Total gas Chromatograph C1 - C5 ROP

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MUD LOGGING SERVICES Time on/off bottom Pump rate Flowrate Pit volumes H2S Mud weight in and out Mud temperature in and out Rotary torque Standpipe pressure Rotary speed Hook load and weight on bit Cement unit pump rate and pressure

These data will be recorded on electronic media, against both depth and time. 3.1.2

A monitor may be installed in the operator’s office to display and record any of these parameters versus depth and/or time.

3.2

Standard Equipment

3.2.1

Total Gas The gas sample is sucked into the unit from a gas trap behind the shakers by a vacuum pump in the unit. An air driven agitator in the gas trap helps liberate gas from the mud. The sample is distributed to the different instruments from behind the mud panel in the logging unit.

3.2.2

INSTRUMENTS:

Flame ionisation (FID) total gas detector.

LOCATION:

Behind main panel in unit. Control valves, instrument attenuation and chart recorder is on main panel.

OPERATION:

The ditch gas sample is brought to the instrument continuously. The sample is ionised in a flame chamber and the charge measured by electrodes. The signal is recorded on a chart and computer. The gas detector is calibrated by injecting a sample of known concentration and calculating chart division per concentration. Zero is to air.

LIMITATIONS:

The gas sample is mixed with air from the trap and the concentration of gas reaching the instrument depends on the positioning and efficiency of the trap. The position of the “gas trap” in the returning mud should be checked twice per hour when circulating. The detector is an accurate piece of equipment which must be calibrated at least once a week. The gas trap should be cleaned daily. FID is most accurate for 0 - 5% gas concentration.

Chromatograph INSTRUMENT:

FID chromatograph.

LOCATION:

In main panel, complete with attenuation and strip chart, signal link to computer and integrator.

OPERATION:

Gas sample brought to instrument by vacuum pump. Sample is regularly automatically injected and carried through selective columns which separates the gas components C1-C5, allowing them to be sampled individually. The result is recorded on a chromatogramme and analysed on an automatic, programmable on-line integrator. The chromatograph is calibrated by injecting a sample of known proportions of C1-C5 and converting chart divisions/integrator response to PPM of individual gases from methane equivalent concentrations measured.

LIMITATIONS:

The chromatograph is limited by the quality of the sample, as described for total gas.

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3.2.5

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ROP INSTRUMENT:

Hydrostatic pressure kelly height meter, geolograph wire or drawworks sensors. The latter is favoured, for safety of use and ease of maintenance.

LOCATION:

The hydrostatic transducer is fixed to the kelly (top drive) hose and an oil or water line is taken from transducer to a reservoir in the derrick. The movement of the kelly (top drive) changes hydrostatic in the line which is converted to an electrical signal by the transducer. Alternatively an electromechanical transducer detects rotation of the drawworks drum or a geolograph wire monitors the position of the travelling blocks. A signal cable leads from whichever transducer to the unit.

OPERATION:

The signal is sent to the computer, and ROP calculated, displayed and stored. Correction for drill string elasticity is required. A chart display should be provided of kelly/top-drive motion.

LIMITATIONS:

The hydrostatic hose is vulnerable to damage and restriction. If rigged up and calibrated properly, the system is accurate. The hydrostatic kelly height meter and the geolograph are restricted to while-drilling monitoring only if connected to the kelly (less restrictive with top drive hose), whilst the drawworks transducer can additionally monitor tripping. The latter is therefore favoured. An independent heavecompensation system should be provided on floating rigs.

Pump Strokes Indicator INSTRUMENT:

Dual pump counter.

LOCATION:

SPM digital readout, strip chart and computer calibrated in gpm and total stroke counters per pump on panel computer. Pick-up units are mounted on each pump.

OPERATION:

The pick-up units are microswitches actuated by an arm mounted so that the switch opens for each pump stroke. The signal is converted to SPM in the computer. Alternatively, proximity switches are used, detecting pump motion by induction methods. A flowmeter measures mud flow out of hole.

LIMITATIONS:

The microswitches can become jammed, the pick-up arms misaligned and either miss strokes or double the count. If set up and maintained properly, the system is reliable and accurate. If mounted internally in the pump, proximity switches are very accurate.

Pit Volume Totaliser LOCATION:

In main panel. Sensors are located over each pit in mud system.

OPERATION:

The pit level is sensed by sonic pulses bouncing off the mud level, or a float with magnets on a pole which trips reed switches as it passes. The signal is sent to the unit and recorded on a strip chart and computer. Non-linear calibrations (multi-stage) may be required for complex pits.

LIMITATIONS:

3.2.6

The instrument is subject to interference if the dish is dirty and the sensor is vulnerable to the corrosive atmosphere above a mud pit. Steam from the pits can cause severe signal scatter. If sensors are kept clean and pits are not too steamy, the system is very accurate.

H2S Detector INSTRUMENT:

Infra-red H2S detector or electronic (platinum electrode).

LOCATION:

Either in panel or separate instrument on bench, linked to the computer.

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OPERATION:

Continuous ditch gas sample from vacuum system. H2S will blacken a white sensitive ribbon and a light detector will give signal to alarm. The instrument can be calibrated by inserting a blank in front of ribbon. The alternative method measures the resistance of a platinum electrode which varies in the presence of H2S.

LIMITATION:

The H2S detector is limited by the quality of the gas sample. The ribbon should be periodically checked to ensure sensitivity at intervals of one week maximum, and each sensor calibrated once per week with test cylinders of H2S.

Mud Weight In and Out LOCATION:

In main panel with computer storage and chart readout. Sensors are located in ditch behind shakers and in active pit.

OPERATION:

The sensors are probes which measure differential pressure across a diaphragm against a reference air pressure. This equipment is calibrated by zeroing in air and spanning to a known fluid density, e.g. freshwater. Alternatively, a heavy ball hangs in the mud and its buoyancy measured (strain gauge), or gamma ray absorption of the mud is monitored.

LIMITATION:

3.2.8

3.2.9

The diaphragm of the differential pressure sensor must be located in moving mud so as not to become clogged with cuttings. If set up and calibrated correctly, it can be fairly accurate but must be cleaned regularly.

Rotary Torque LOCATION:

Digital storage and strip chart on panel. Current detector clamped to power cable to rotary drive (Hall effect).

OPERATION:

Sensor detects current drawn by rotary table/top drive and converts it to signal which is displayed in unit. The measured torque in amps must be converted to a force unit for display and storage (i.e. k ft lbs or KNM).

LIMITATION:

None, provided clamp securely fixed.

Standpipe Pressure LOCATION:

Digital storage and strip chart on panel. Pressure transducer on standpipe manifold.

OPERATION:

Mud pressure operates a diaphragm in a housing. The transducer converts pressure to signal which is sent to unit. The instrument is calibrated using a dead-weight tester.

LIMITATION:

This instrument is rugged and reliable and needs little attention.

CALIBRATION:

Should be performed with a deadweight tester, once per well.

3.2.10 Rotary Speed LOCATION:

Digital storage and chart on panel. Sensor under rotary table. Alternatively a signal is taken from the top drive control unit.

OPERATION:

A proximity device senses a mass fixed to rotary drive (induction). The signal is sent to unit and displayed.

LIMITATION:

The rotary table sensor is subjected to a lot of vibration but if mounted correctly is reliable and accurate.

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3.2.11 Hookload/Weight on Bit LOCATION:

Digital storage and panel display with hookload/WOB electro switch plus strip chart recorder. Transducer near deadline anchor with hydraulic line “Tee” into rig, hydraulic line to load cell, or clamp-line tensiometer type on drill line. Clamp-line tensiometer is the favoured sensor type, being independent of rig equipment.

OPERATION:

Alternatively, hydraulic pressure from a load cell is converted to signal in transducer. Signal is displayed in unit. WOB is calculated from string weight (input) minus last free-rotating hookload. This value of current string weight must be checked and updated regularly (once per single/stand).

LIMITATION:

The hydraulic system is dependent on the rig Martin Decker system. Very few problems occur so long as hydraulic system does not leak. The independent clampline tensiometer should be installed wherever possible. This sensor may require removal (simple) during slip and cut operations.

4.

ADDITIONAL INFORMATION FOR PRESSURE DETECTOR SERVICES

4.1

In additon to the basic mud logging service, provision may be made in the work order for data/pressure engineering services. The Pressure Detection Engineer (PDE) provides an estimate of formation pressure with the aid of offline computer programmes. A pressure log will be prepared as specified in Section 6.

4.2

The Pressure Detection Engineer will report to the operator’s representative on arrival at the wellsite.

4.3

The pressure detection service will be considered ready when: i) ii)

4.4

Computer and additional equipment is rigged up and checked out. When the pressure detection engineer is at the wellsite.

During the course of his duties the PDE will report the following to the operator’s representative: i)

Any change in “d” exponent, shale density, shale factor, flowline temperature or gas trends which could indicate overpressure.

ii)

Any change in drilling parameters which could be significant in terms of hole condition, e.g. torque change.

iii) Pit gains or losses, drill breaks, significant gas peaks, hole swabbing on trips. In addition, the PDE will make a daily written report of the parameters monitored, plus present any printouts from the offline programmes requested by the operator’s representative. The PDE will keep the operator up-to-date on pore pressure and fracture pressure estimates. 4.5

Pore Pressure Evaluation Methods: Procedures, Limitations and Accuracy

4.5.1

“d” Exponent Calculation and use of “d” exponent is a method of normalising penetration rate so as to show up changes in formation compaction. “d” exponent is calculated at 5m intervals using an equation of the type:

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MUD LOGGING SERVICES R

R

= ROP in FT/HR

log 60 N

N

= RPM

log 12 W

W = WOB in KLBS

d = 106D

D

= Hole Size in Inches

The exponent is usually corrected for mud weight, giving dxc: dxc = d. Weq ECD

Weq ECD

= =

Normal pressure grad. Effective circulation density

dxc is plotted on semilog paper and a normal trend is established in the shallower formations, usually clays. Deviation from the normal trend in shales can indicate overpressure and this is calculated. Pore Pressure lbs/gall

=

Normal Gradient lbs/gall

x

dxc NORM dxc OBSERVED

An overlay is constructed for different mud weights using the formula above. Different companies use variations of the basic formula, correcting for other variables, e.g. bit wear - for exact formula in use, refer to service company. Limitations The “d” exponent only holds good for clean shale (mudstone) formations. In other types, it is very variable and trends are difficult to spot. The Jordan and Shirley method, illustrated above, was derived in the Gulf Coast so experience in the operator’s area is advisable. Formation changes, e.g. increase in silt content, can shift the trend to resemble overpressure. Changes in certain conditions, e.g. a new bit, bit wear, can produce shifts in the trend which must be recognised. Use of a turbine produces a wide range of trends since WOB is not necessarily held constant, therefore dxc evaluation during turbine runs is not a valuable overpressure indicator. Interpretation of “d” exponent trends when drilling with PDC bits is unreliable due to bit cutter effects and bit wear. A bit torque-based estimate of formation drillability is preferred with PDC bits. Accuracy Individual readings may be very accurate. Trend interpretation depends on experience and judgement of the engineer. Dxc is a useful tool only if drilling through thick uniform shale sections with conventional rotary methods. 4.5.2

Shale Density Clean shale cuttings are taken from each sample and air dried on paper towels. The cuttings density is measured either with a mud balance or in a variable density column. Variable density fluid columns may require toxic fluids and thus handling restrictions should be referred to. a)

Mud Balance The dried cuttings fill a mud balance until it reads 8.33 and fresh water is added until the cuttings are completely covered. The cap is put on the balance and the density is read. This is D1.

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Using the formula:

S.G.

=

8.33 16.66 - D1

the specific gravity of the cuttings is determined. Limitations Individual cuttings are not selected so there is a chance of formation contamination including cavings. This method will produce a trend which can be valuable. Accuracy This method is not accurate and wide variations can be seen. but the trend is useful and is a good alternative to a density column. b)

Variable Density Column Dried cuttings are placed in a graduated glass column, filled with a mixture of liquids having a variable density. The column is calibrated by placing reference beads of known density in the column and plotting their positions on a chart. Limitations The cuttings can either float if too wet or sink if too dry and absorb the fluid. The chemicals used to create the variable density column are hazardous. Accuracy Results from the column can be fairly accurate although agitation of the apparatus on an offshore rig can upset the calibration and it is very difficult to get a linear change in density when making up the column.

4.5.3

Shale Factor Shale factor is also known as the Methylene Blue Test (MBT). Generally, as shales compact with depth, the proportion of illite clay minerals increase relative to montmorillonite. In medium depth formations, a higher proportion of montmorillonite is indicative of overpressure. The percentage of montmorillonite in the shale cuttings is determined by the MBT where the cation exchange capacity of the sample can be measured. This increases with montmorillonite content. Limitations The proportions of montmorillonite may change from formation to formation, so results can be misleading. However, as in all pore pressure determination methods, trends not individual results are significant. While the MBT may not prove much in itself, it is a useful tool to back up other information and present a fuller picture of formation trends. Accuracy The method is fairly accurate, the interpretation is not.

4.5.4

Mud Temperature Abnormally pressured formations have high geothermal gradients since such formations act as insulators. Platinum resistance probes are mounted to measure mud flow in and out. Advanced equipment is self-calibrating, alternatively the equipment is zeroed in ice and calibrated to boiling water.

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Limitations Measurement of flowline temperature can be a useful diagnostic tool, but in the offshore environment the temperature trend is greatly distrubed by the cooling effect of the sea. Mud transfer to active pit and water addition can cool the mud system, making the value of temperature readings very doubtful. The probes can become clogged with mud but, if kept clean, work well and are very accurate. Accuracy The temperature probes are accurate, the method of overpressure detection is not. 4.5.5

Gas Readings The PDE pays particular attention to the total gas readings. BACKGROUND GAS: is the usual gas level from the drilled formation cuttings. Any increase without significant increase in ROP indicates the well is close to balance. CONNECTION GAS: is a small amount of gas generated on bottom during a connection. It could indicate swabbing as well close to balance. TRIP GAS: is an accumulation of gas circulated up from bottom after a trip. It may be swabbed gas or, as above, the well is close to balance. Limitations Drilling behaviour, e.g. reaming, can increase the cuttings/cavings in the mud. Gas curves are open to interpretation but generally an increase in background trip and connection gases are an indication of near balance.

4.5.6

Mud Weight Mud weight out is monitored and reductions due to gas cutting noted. Generally, gas cutting is not serious, since most expansion occurs in the top few hundred feet of the well thus having little effect on the total hydrostatic. Reduction in mud weight due to formation water influx should be taken seriously by the PDE and observations should be reported to the operators representative and checked for validity with the mud engineer.

4.6

Offline Programmes Overpressure information is determined with the aid of an overpressure evaluation suite of programmes.

4.6.1

OVERBURDEN GRADIENT DETERMINATION is used in the calculation of fracture gradient. This requires knowledge of formation bulk density or data from the sonic log.

4.6.2

ADVANCED OVERPRESSURE ANALYSIS utilises dxc and estimates overburden stress gradient, fracture gradient, porosity, matrix stress, and pore pressure.

4.6.3

FLOWLINE TEMPERATURE ANALYSIS including end to end plot. See limitations in foregoing section on mud temperature.

4.6.4

Wireline Plotting Suite and Determination of Clay Porosity These programmes plot drilling and wireline parameters or density sonic cross plot for clay porosity. This is performed rarely by mud logging companies.

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Summary - Pore Pressure Evaluation, Limitations and Accuracy Formation pore pressures are estimated by looking at all the evidence from data gathered. Since much of this evidence is based on deviations from established trends for each piece of data, the quality of the service depends on the skill and experience of the engineer. He will use his plots, knowledge of the area, and observation of well behaviour (e.g. condition of cuttings at shakers) to estimate pore pressure. While dxc can give direct results, other methods only give an estimate of degree of overbalance. The system is open to interpretation and the operators representative should not rely solely on results from computer programmes. The system is not accurate but if the job is conducted properly, recommendations for optimum overbalance can be provided.

5.

REPORTING Reporting procedures are outlined fully in the BP Technical Specification for Mud Logging Services. Two daily telexes are required.

5.1

The Daily Pressure Telex should contain the following information given at 10m (30 ft) intervals: Depth Drill Exponent Pore Pressure Mud Weight ECD Fracture Gradient Static + Dynamic Overbalance Total Gas Shale Density Flowline Temperature.

5.2

The Daily Geological Report should contain: Date, Well No., Day No., Depth Data, Rig Name, RTE Lithological Data Formation Tops (Provisional) Shows

6.

LOG FORMATS Three logs are to be compiled at the rigsite - the Formation Evaluation Log (FEL), the Pressure Evaluation Log (PEL) and the Drilling Evaluation Log (DEL). Further details can be found in the BP Technical Specification for Mud Logging Services.

6.1

The Formation Evaluation Log The FEL is based upon the cutting register and is subdivided on a 1:500 depth scale, into: Track 1 :

Drillstring parameters, i.e. WOB RPM torque (WOB in klbs, torque in kftlbs).

Track 2 :

Remarks, e.g. mud weight/ECD, surveys, shoe depths, cores, shows, etc.

Track 3 :

ROP and bit data (bit type, size, jets, in/out depths, footage, hours, grade).

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Track 4 :

Depth, MD/TVD.

Track 5 :

Cuttings percentage log including cement, junk, LCM, cavings, etc.

Track 6 :

Symbolic lithological interpretation.

Track 7 :

Percentage hydrocarbon gas in air, normalised for ROP/temperature.

Track 8 :

Lithological description.

The Pressure Evaluation Log The PEL, again on a 1:500 depth scale, specifies:

6.3

Track 1 :

Depth BRT/TVD etc., shoe depths, liner hangers.

Track 2 :

Lithological interpretation completed after review of all data, i.e. logs, cores.

Track 3 :

ROP.

Track 4 :

D exponent, bulk density and shale factor if appropriate.

Track 5 :

Pressure evaluation including calculated pore pressures and fracture gradients, mud weights, LOT data, ECD, etc.

Track 6 :

Gas, total methane equivalent from summation of chromatograph.

Track 7 :

Variable - unspecified, e.g. flowline temperature, information from MWD (gamma ray) etc.

The Drilling Evaluation Log The DEL, again on a 1:500 depth scale, specifies: Track 1 :

Weight on bit (klbs), rotary speed at bit (rpm).

Track 2 :

Rate of penetration (m/hr), corrected for drill string elasticity effects.

Track 3 :

Interpreted lithology.

Track 4 :

Surface torque, maximum surface torque (kft.lbs).

Track 5 :

Depth BRT (m).

Track 6 :

Standpipe pressure (psi), mud flow in (gpm).

Track 7 :

Hydrostatic pressure, overbalance (dynamic) pressure (psi).

Track 8 :

Left blank for BP-requested derived parameters.

Track 9 :

Lithology descriptions, survey data, bit gradings, etc.

7.

MUD LOGGING END OF WELL REPORT

7.1

Contents A typewriter or word-processor must be available at the wellsite.

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From the Base Mud Logging Service, the following information must be included in the End of Well Report: •

A description of services provided, including personnel listing.

•

A full Well FEL (1 sepia only, plus 1 paper copy per report).

•

A full Well DEL (1 sepia only, plus 1 paper copy per report).

•

A full Well Numeric Hardcopy Printout.

•

A sensor Hook-Up verification sheet.

•

A sensor Calibration Record.

•

Sensor History sheets.

•

A report on metal returns as removed from the flowline magnet.

If contracted to provide further services, the additional reports as specified within the relevant technical specification shall also be included. BP retains the right to alter the format and content of the required End of Well report at any time. 7.2

Delivery One provisional copy of the End of Well report, including provisional logs, is to be delivered to the appropriate BP geological co-ordinator, within fourteen days of the end of the well. The reports will then be checked and the contractor notified that the specified number of copies of the report should be forwarded, within seven days of notification. (The required number of copies should be specified by the local BP Operations Geologist). One copy of the approved report, including logs, should be forwarded direct to the BP Operations Geologist. The sepia drafting film employed on all logs is to have a minimum thickness of 0.030”. All data are to be regarded as confidential, including originals of graphic logs, work sheets and gas or other sensor charts. All such information will, if requested, be handed to BP Rig Geologist, or other personnel as defined by BP, at the completion of the well. The on-line chart recorder outpouts, and computer time-based data records for the complete well, are to be offered to the Senior Drilling Engineer at the end of the well.

8.

PROVISION OF DATA TAPE FOR POST-WELL ANALYSIS In general, the operation being conducted dictates the data monitoring and acquisition requirements. The current requirements are relatively simple. These consist of providing drilling performance data on tape, for the four operations listed below: a) b) c) d)

Drilling Hole Opening Underreaming Coring

(Operation Code = (Operation Code = (Operation Code = (Operation Code =

°D’) °H’) °U’) °C’)

These performance records are identical and consist of depth based data. Therefore assuming that the mud logging unit can allocate an operation code by manual or automatic means, it is anticipated that there should be no problem obtaining these records.

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Parameters Required for Post Well Analysis The following parameters shall be recorded on a per unit depth increment basis for each of the four specified operations: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17.

8.2

Depth. BHA Run Number. Operation Code. Date. Time. Time on Bottom. Time off Bottom. Cumulative Rotating Hours on Bit. Mud Flow In - calculated from pump performance. Total SPM (to the well). Surface Rotary Speed. Free rotating off bottom string weight (Operator input). Weight on Bit (Surface). Average Rotary Torque (Applied). Maximum Rotary Torque (Applied). Standpipe Pressure. Mud Weight In.

Definitions and Frequency of Recording Data records are required on per unit depth increment basis with: a)

Parameter 2 is the sequential number of the BHA run which completed the current depth increment.

b)

Parameters 4 and 5 being recorded at the completion of the current depth increment.

c)

Parameters 6 and 7 are the summation of times for the current depth increment.

d)

Parameter 8 is the summation of rotating hours for that particular BHA run up until the end of the current depth increment.

e)

Parameters 9 - 17 are derived statistically for each parameter over the current depth increment.

Note: A record must exist for every unit depth increment even if no data has been recorded. It should include the relevant BHA run number and operation code along with substituted standard error codes. 8.3

Units in which Data must be Presented These data shall be presented in the following engineering units:

Parameter No.

Description

Units

1 2 3 4 5 6 7 8 9 10

Depth BHA Run Number Operation Code Date Time Time on Bottom Time off Bottom Cumulative Rotating Mud Flow In - Calculated Total SPM

Unit of depth increment YYMMDD HHMMSS Minutes Minutes Hours GPM SPM

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11 12 13 14 15 16 17 8.4

Section

Surface Rotary Speed String Weight Weight on Bity Average Rotary Torque Maximum Rotary Torque Standpipe Pressure Mud Weight

RPM Klbs Klbs Kft.lbs Kft.lbs psi lbs/gal

Data Verification As most Driling engineering work is based on historic data, every effort shall be made to ensure that the performance records are as complete and accurate as possible. This can only be achieved if the following rules are enforced: 1.

The Sensor Calibration Check programme, as specified in the Technical Specification for Mud Logging Services, shall be rigidly enforced.

2.

All equipment or sensor failures shall be reported. The appropriate action shall be taken immediately.

3.

The Performance records shall be checked for erroneous readings and missing values. These must be substituted with a standard error code, e.g. -999.25.

Note: It is anticipated that erroneous or missing data values will most likely occur at the start or the end of bit runs. 8.5

Presentation of Digital Data The data specified within Section 8.1 should be provided on a magnetic tape which shall conform to the Logging Industry Standard (LIS) format. The tape density should be 800 or preferably 1600 bpi. Contractor must be capable of providing tapes ex-rig site within 4 working days of the data being requested, and should have the capability of editing tapes in the UK should the need arise. The tape should be forwarded to the BP Drilling Operations Group Senior Drilling Engineer. The following mnemonics should be used to define the data records: a)

b)

Wellsite Information (Record Type 34)

Parameter

Description

Mnemonic

1 2 3

Well Name Operator Drill Datum Height

WELL OPER OSET (wrt well ref pt.)

Data Records (Record Type 0)

Parameter

Description

Mnemonic*

1 2 3 4 5 6 7 8

Depth BHA Run Number Operation Code Date Time Time on Bottom Time off Bottom Cumulative Rotating Hours

DMEA BRUN OPCD DATE TIME TON TOF BDTI

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DRILLING MANUAL SUBJECT: 9 10 11 12 13 14 15 16 17

MUD LOGGING SERVICES Mud Flow In - Calculated Total SPM Surface Rotary Speed String Weight Weight on Bit Average Rotary Torque Maximum Rotary Torque Standpipe Pressure Mud Weight In

MFIA SPM RPMA STWT WOBA TQA TQX SPPA MDIA

* As defined in the Data format specification (record type).

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ELECTRIC LOGGING OPERATIONS USING PRESSURE EQUIPMENT

SCHLUMBERGER THROUGH TUBING/PRODUCTION OPERATIONS WITH PRESSURE EQUIPMENT 1.

TESTING RISER The following procedure will be followed for testing Schlumberger “Grease Injection Lubricator”.

1.1

Assemble lubricator with cable and bridle but do NOT install tool or gun.

1.2

Fill up lubricator with water by pumping slowly through circulating head or bleed-off valve.

Note: Do not use diesel oil for pressure tests because of the danger of flash ignition. 1.3

Energise the seal with grease. If this is insufficient to hold pressure also energise the stuffing box.

1.4

Slowly pressure test the lubricator to the required value.

Note: Pressures over 5000 psi require the special 10,000 psi riser/BOP. 2.

TESTING BOP’S Prior to rig up the Schlumberger BOP will be tested by inserting a 7/32” (or 3/16” depending on cable size) “I” shaped test rod between rams. The cable is not to be used for this purpose since pressure leaks occur through the armour.

3.

PICKING UP THE TOOL OR GUN

3.1

Install the gun in lubricator and tighten Bowen Union fully.

3.2

If the well is under pressure, leave about 1.5m between the top of the gun and the stuffing box, then manually pull on the cable until the tool or gun touches the stuffing box. This is to prevent the tool or gun becoming jammed when pressure comes onto the riser, and to avoid snapping the cable at the head.

3.3

Slowly pressure up the lubricator to the THP and inspect for leaks.

3.4

Ensure tool trap is closed.

3.5

Open the master gate. Then open the swab valve slowly.

3.6

While Schlumberger are in the tubing, ensure the Xmas tree and circulating head valves have a sign tied onto them to act as a warning against inadvertent cutting of the wire.

Note: If the riser has to be lifted or lowered to install tool or gun, there will be an error in the “zero” of twice the distance moved. If it is essential to have no pressure leak when the BOP is closed on the cable, a note to this effect should be made in the programme. In this case 2 BOP’s will be used in tandem and heavy grease injected between the two sets of rams to act as a sealant.



Index Prefixes 0000


1000

Drilling

2000

Casing and Tubing

3000

Cementing

4000

Drilling Fluids

5000


6000


7000

Well Evaluation

8000






Section

Description

8000

MARINE AND MISCELLANEOUS

8150/JAK

Positioning Self-Elevating Jack-Up Rigs Alongside a Fixed Structure

8160/JAK

Pulling Away From Fixed Structures

8200/JAK

Jacking Procedures

8300/JAK

Heavy Weather Policy - General

8410/WYF

Formation Saver Valve Installation Procedure Wytch Farm

8420/WYF

ESP Completion Running Procedure Wytch Farm


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POSITIONING SELF-ELEVATING JACK-UP RIGS ALONGSIDE A FIXED STRUCTURE

INTRODUCTION The following information is intended for use during the positioning of a jack-up rig alongside a fixed structure. For general information, jack-up rig positioning reference should be made to Section 11 STANDING INSTRUCTIONS AND GUIDELINES FOR OFFSHORE MARINE OPERATIONS.

2.

RIG SUITABILITY

2.1

The selection of a jack-up drilling rig for operations alongside a fixed structure should take into account, but not be limited to, the following factors: a)

Ability of unit to carry out workscope.

b)

Location of fixed structure.

c)

Relative position of subsea obstructions, e.g. pipelines, wellheads, etc.

d)

Water depth.

e)

Time of year.

f)

Design criteria wrt leg stress under hostile environmental conditions.

2.2

In circumstances where there is a possibility that environmental conditions or water depth may lead to high stress being placed on the rig legs (i.e. greater than 75% of design maximum), MSDD may request BP Engineering Department, London, to run a stress analysis of the units legs to examine its ability to withstand the high stress and continue working safely as required.

2.3

When a location is proposed which is a “new site” (i.e. a jack-up drilling rig has not been placed in the vicinity previously), it will be necessary for a site survey to be prepared, which includes a number of core samples taken in the expected leg footprint areas. These core samples will be analysed by Engineering in London to ascertain the suitability of the soil conditions for emplacement of a jack-up drilling rig at the location, with respect to spud-can penetrations and the possibility of leg punch through.

3.

JACK-UP RIG ALONGSIDE A FIXED STRUCTURE

3.1

Location Information and Site Survey Detailed charts of any seabed obstructions, such as pipelines and previously drilled wells, must be available for a minimum of 3 miles radius from the centre of the fixed structure. This is to allow the selection of a suitable stand-off location for anchor deployment, or to await a suitable weather window for approach to the structure.

3.2

Tug Requirements

3.2.1

A minimum of two (2) tugs will be required for any tow, with a third or on occasion a fourth tug available for final approach/positioning.

3.2.2

Each tug for towage shall have a minimum of 8000 BHP. Additional tugs for final approach/positioning may on occasion be a minimum of 6000 BHP depending upon circumstances.

3.2.3

The tugs shall be positioned for towage as directed by the BP Towmaster.

3.2.4

The tug decks must be clear of cargo to allow for ease of anchor handling, towing, etc.

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3.3

Anchoring and Towing Equipment Required

3.3.1

On the rig the following items should be available and in good order, having been inspected prior to departure from the old location:

3.3.2

a)

Port and Starboard anchor winches, complete with a minimum of 700m x 1 5/8” wire suitable anchors, preferably rigged for deployment on the stern quarters.

b)

Main tow bridle.

c)

Auxiliary tow bridle.

d)

Emergency tow bridle rigged for immediate use.

e)

Port and Starboard stern towing brackets rigged with towing pennants (preferably of the quick release SMIT type).

f)

Sufficient anchor buoys and riser pennants.

On each tug, the following items should be available: a)

Main tow wire and spare tow wire.

b)

Towing springs.

c)

Towing pennant wires and shackles.

3.4

Rig Positioning and Navigation Systems

3.4.1

Navigating the rig to within 100m of a fixed structure may be achieved using one of the following systems (as detailed in Section 8120/GEN): a)

SYLEDIS.

b)

PULSE-8.

c)

TRISPONDER.

The selection of a particular system will depend upon the position of the structure relative to land masses and other structures in the vicinity. 3.4.2

Final positioning alongside a structure where accuracy to within ± 1.5m is required may be achieved using a plumbline/pole system. In such a system, two or more plumblines are suspended from known points on the structure. On the rig poles are set up to protrude from the stern of the rig with a taut line stretched between them. The position of the plumblines and poles is carefully set to be such that when certain points on the taut line touch the plumblines, the rig is in position. As an alternative method, the plumblines may be dispensed with and fixed points on the platform itself, e.g. leg centres, used to line up with marks on the taut line.

3.4.3

In circumstances where extreme accuracy is required, i.e. less than 1.5m, a theodometer system shall be used. This system requires a theodometer to be positioned on the structure. As the rig approaches, the theodometer is directed at accurately positioned prisms on the rig. Information is then transmitted by the theodometer to a computer system on the rig which interprets the readings and displays the relative rig/structure orientation on a VDU for use by the Towmaster in positioning the rig.

3.5

Final Approach a)

Approximately 3 miles from location, the tug towing positions should be adjusted to the following orientation:

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1)

Lead tug on the bow.

2)

Second and third tugs on the stern quarters.

The rig can now be conned to the stand-off position. b)

At the 3 mile position, the legs should be lowered to maintain an adequate spud can to seabed clearance for approach to the stand-offposition.

c)

Approximately 100m - 120m from the structure (stand-off position), the rig is held stationary on the desired heading and the legslowered to pin the rig in position. The hull is then elevated to an air gap of approximately 10 ft for anchor deployment and preparation of final positioning equipment. Weather conditions are closely monitored at this stage and the final approach will not commence until the conditions are such that the maximum sea state is 2.0m significant wave height or less and the tide is at or near slack water.

d)

The stern tugs are disconnected from their towing positions and used to run the rig anchors to a position as determined by the BP Towmaster. Anchor holding shall then be proved by test tensioning.

e)

On completion of anchor running, the stern tugs are re-connected to the rig quarter towing points as before and by paying out their towlines are directed to a position approximately 600m from the rig where they will drop their ships’ anchors. By slacking their anchor chains and hauling in on towlines, they will position themselves at the mid point between anchor drop and rig.

f)

On commencement of the next suitable slack tide, the tugs lines and rig anchors are tensioned and the hull floated with legs raised to give a spud can to seabed clearance of approximately 2m.

g)

The bow tug will be placed on minimum power to act as a restraining force and the rig will be moved toward the structure using the rig anchors and tug tow winches.

h)

When in the final position, the rig is pinned, the position checked, and once confirmed within tolerance, jacking continues until a suitable preload air gap is attained. At this point the tugs are released from the stern quarters and rig anchors recovered. The bow tug may remain secured to the bow for the duration of the preload, dependent upon rig insurance requirement. In any event one tug must remain on location until preload is complete.

Note: a) If a separate submersible firewater pump is required to supply the structure, it should be connected and placed at online status while the rig is at the stand-off position. b) Elevation, preload and lowering of the hull are carried out in accordance with Section 8200/JAK.

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PULLING AWAY FROM FIXED STRUCTURES

1.

LOCATION INFORMATION AND SITE SURVEYING

2.

TUG REQUIREMENTS

3.

ANCHORING AND TOWING EQUIPMENT REQUIRED ON TUGS AND RIGS

For information on the above topics, refer to Section 8150/JAK. 4.

PULLING OFF

Note: Elevating and lowering of the rig is to be carried out as laid out in Section 8200/JAK. 4.1

4.2

Before commencing pulling off operations, weather and sea conditions must be suitable, i.e: a) b) c) d) e)

Current pushing rig away from structure. Wind pushing rig away from structure. Seas/swell less than 2m (5 ft). Swell period as per rig operations manual. Good visibility, preferably during daylight.

1.

When the rig is ready for pulling off and all conditions in 4.1 are satisfied, the rig is jacked down to between 3 and 6m (10 and 20 ft) airgap and the water tower jacked up.

2.

Connect the most powerful tug to the bow main tow bridle.

3.

Run both rig bow anchors to ± 400m (1200 ft) at 45 deg to the rig heading. Tension up on both anchors to check they are holding, rerun if dragging is suspected.

4.

Attach the two smaller tugs to the rigs stern bollards (if one is more powerful, position it on the weather side). The stern tugs now slack off on their tow wires until they are ± 600m (2000 ft) from the rig at 45 deg to the rig centre line, where they drop anchors.

5.

By winching in on their tow wires and slacking off on anchor chains, the stern tugs position themselves ± midway between rig and anchors. See Figure 1.

6.

All wires are now tensioned up and anchors checked for dragging.

7.

Jack the hull into the water to check draft ± 2m (5 ft), and check hull integrity.

8.

Jack to floating draft with the bow tug on half power.

9.

The rig is now pulled off on a foot by foot basis by tensioning up on the bow anchor wires and slacking off on the stern tugs tow wires.

Note: The legs should be jacked clear of the seabed as quickly as possible to avoid dragging. 10. With the rig ± 150m (500 ft) from the structure, the rig can either be pinned or remain floating, depending upon sea/weather states. Both stern tugs can now retrieve their anchors, with the stern tug to be used to assist in the tow being released from the rig and the other remaining attached. 11. The released tug can now retrieve the rigs bow anchors whilst the other two tugs keep the rig on station (if the rig has not been pinned). On completion of anchor retrieval, attach the loose tug to the bow auxiliary tow bridle and commence a slow tow whilst the legs are jacked fully up.

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PULLING AWAY FROM FIXED STRUCTURES

1.

Using the method laid out in 4.2 for pulling off can result in circular oscillation of the rig when the rig starts to float. With the rig in close proximity to a structure, a quick pull off procedure using only tugs and no anchors may be more desirable. The alternative pull off procedure is as below:

2.

Three tugs are attached to the rig as shown in Figure 2 with the most powerful attached to the bow.

3.

With all tow wires tensioned up, jack into the water to check draft and check hull integrity.

4.

Jack to floating draft with tugs on half power and pull rig away from structure.

5.

It is important that jacking of the legs above the seabed is done with the utmost speed when using this method to avoid dragging.

6.

It is also essential that any current and/or wind is pushing the rig away from the structure.

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PULLING AWAY FROM FIXED STRUCTURES FIGURE 1

STARBOARD STERN TUG

BOW TUG

45°

12 00 '

SUBJECT:

Section

20

PORT STERN TUG '

00 2179/182

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PULLING AWAY FROM FIXED STRUCTURES FIGURE 2

STARBOARD STERN TUG

75° BOW TUG

'

75°

1000

SUBJECT:

Section

PORT STERN TUG

2179/183

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JACKING PROCEDURES

1.

PREPARATIONS FOR ELEVATING THE UNIT

1.1

Main generators, electrical switchboards, jacking controls and jacking motor control centres should all be checked for full operational capacity prior to elevating the unit.

1.2

All spud cans should be checked to ensure that they are filled with water, and weather reports for the site obtained and checked for favourable elevating conditions. Wind, wave and current directions should also be checked and the rig positioned with tugs and anchors to minimise swing and drift. If the unit is allowed to drift or swing as the cans contact the bottom, severe damage to the cans or legs can occur.

2.

ELEVATING THE UNIT

2.1

The prevailing and future weather forecast should be obtained and it should be ensured that the weather will not worsen during the period of elevation.

2.2

Water depth should be checked and an accurate measure at each leg location should be taken and recorded.

2.3

The pump tower is submersed as legs are lowered. When pumps are below surface, testing of pumps, hoses and connections must be undertaken.

2.4

The legs should be lowered to seabed so that they touch bottom simultaneously. The hull is then elevated maintaining a horizontal level plane within three tenths of a degree. A minimum air gap should be maintained between the bottom of the hull plating and the crest of the prevailing waves. The air gap must not exceed about three feet. At this point jacking should be stopped, the hull levelled and checks made to ensure that all brakes on the jacking unit are properly engaged.

3.

PRELOADING

3.1

The total amount of preload for the rig is the variable load on board plus the preload ballast. These are added together for the total required preload. The weight must be equally supported by all the legs. Leg penetration of the seabed should be recorded and a watch kept to observe if any settling of the legs occurs.

3.2

Should differential settling in excess of one degree occur, the following steps should be taken: a)

Dump preload until total weight of unit is as determined in drilling contractor’s operating manual. This weight must be equally supported on all the legs.

b)

Level the unit by jacking down the higher leg or legs.

c)

Jack to required (preload) air gap.

d)

Increase the preload to the required amount.

3.3

If differential settling continues whilst dumping the preload and it reaches one and a half degrees, then the unit should be levelled by jacking down on the higher leg(s). Dumping preload may continue during the levelling process.

3.4

When the unit is fully preloaded, it should be allowed to stabilise for a period of time. The period of time is determined by the soil condition of the area, for example in soft bottoms there should be no settling for a period of four hours with the entire preload applied.

3.5

After footings have proven solid, the preload should be dumped and the hull elevated to its final position. The unit must be maintained within three tenths of a degree of the horizontal level plane whenever it is in the elevated position.

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JACKING PROCEDURES

4.

DIFFERENTIAL LEG PENETRATION

4.1

If whilst preloading the unit a differential leg penetration of greater than that determined in the drilling contractor’s operating manual is sustained, then cores must be taken of the sub-seabed in order to determine the actual lithology. This is done so as to minimise the danger of “punch through” at a later stage in the operations. A number of accidents with jack-up rigs have been caused over recent years by this phenomena.

5.

PREPARATION FOR LOWERING THE UNIT

5.1

It must be ensured that the unit is seaworthy, and that variable load is less than the allowable maximum and positioned to provide equal loading on each leg. Ensure that rack chocks are disengaged.

5.2

Unit must have zero list and trim when afloat and variable load and ballast should be moved to achieve this. Verification should be made that the vertical centre of gravity afloat, total weight of unit and calculated draft do not exceed the allowable maximum.

5.3

Weather forecasts should be checked to ensure favourable conditions.

6.

LOWERING THE UNIT

6.1

The hull should be lowered maintaining a horizontal level plane within three tenths of a degree.

6.2

Qualified operators and observers must be assigned to all key locations during the operation, and they should be in constant communication with each other.

6.3

All jacking systems and warning devices should have been checked previously to ensure correct operation.

6.4

Before the unit reaches water level, it must be ascertained that the mooring system and attending boats are in position to prevent movement while spud cans are still in contact with the ocean bottom.

6.5

Hull should be lowered to predetermined draft conditions for the afloat operations. If cans do not free themselves the hull should be lowered to one foot more than the predetermined floating draft. If they are not freed by this increase, then the jetting systems should be employed.

6.6

If it is necessary to utilise the jetting systems, the following procedure should be used:

6.7

a)

As each leg is independently freed, raise it about 2m (5 ft).

b)

When the final leg is freed, all the legs should be immediately raised to their towing position.

To minimise underwater effects, the unit should not be put under full tow until the legs have been raised to the tow position.

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HEAVY WEATHER POLICY - GENERAL

INTRODUCTION Extreme storm conditions at a particular location cannot be avoided. It is therefore prudent to plan ahead, and where necessary make contingenciesfor such an event. Within the North Sea area, and in and around other parts of the British Isles, extensive historical weather data is available for analysis. This data can be used to predict the most severe storms that can be expected for a particular location. Drilling activity in most northern, central and southern North Sea areas has been such that the above data is now well known and most drilling rigs have defined geographical areas for all year drilling operations. When a well is programmed for exploration or appraisal in an exposed and/or deep water location, historical weather data is used to check that the rig is capable of safely surviving the most severe storm conditions predicted for that location. A mooring analysis or jack-up structural study may be necessary to prove a unit’s suitability for a specific location with its associated environmental conditions. •

For semi-submersible rigs this could be to the West of Shetland.

•

For jack-up rigs this could be in the central North Sea, or Irish Sea.

BP Drilling, as responsible operator, undertakes three main areas of responsibility in planning for storm conditions:

2.

•

Fitness for Purpose.

•

Monitoring and Maintenance.

•

Preparation.

FITNESS FOR PURPOSE All mobile drilling rigs are audited by BP Drilling prior to contract. Audits are conducted to ensure that the rig is “fit for purpose” and is capable of conducting the proposed drilling operations in a safe and cost effective manner. An essential feature of the audit is to ensure that the rigs mooring and propulsion systems (where fitted) are in good order. A weakness in either system would be highlighted and effectively resolved or the rig would not be considered suitable for the proposed workscope.

3.

MONITORING AND MAINTENANCE Effective monitoring and maintenance of the mooring, ballast and propulsion systems is effectively the responsibility of the the Offshore Installation Manager and Rig Owner. However, BP has two effective ways of monitoring rig performance: •

The BP Drilling Representative offshore has a responsibility to ensure that the rig staff maintain and operate the rig in a safe manner. He is the eyes and ears of the BP Drilling Management.

•

MSDD onshore receives daily rig reports which detail essential marine information such as mooring tensions and stability data. By monitoring such information and by assessing rig staff performance during rig moves, MSDD is in a position to evaluate and make recommendations to Drilling Management.

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HEAVY WEATHER POLICY - GENERAL

PREPARATION Responsibility for the safety of the rig and its personnel rests with the Offshore Installation Manager and his senior management. However, BP as a responsible operator also takes an active interest in preparatory work. Preparation for storm conditions should normally start with advance warning from a weather forecast. Weather Forecasts: Individual forecasts are telexed to each rig twice a day by a nominated forecasting contractor. A representative of the forecasting contractor visits MSDD at approximately 0830 each morning to discuss the forecasts in more detail. This arrangement ensures that all offshore and onshore staff are given the earliest indication of forecasted storm conditions. Communication is conducted through normal channels between MSDD, DS and the BP Drilling Representative. Preparations on board the rig should take place as soon as a storm forecast is issued. Specific activity at this stage cannot be defined as it will depend on the severity and imminence of the forecast and instructions contained in the rig’s Operations and Emergency Procedures Manuals. However, consideration should always be given to the following: Rig operation in progress or planned at the time. Wind speed and direction. Sea and swell height, period and direction. Mooring tensions: original insurance tensions and balance between moorings. Anticipated or actual rig heave. Anticipated or actual riser offset. Making the well safe, prior to unlatching. Unlatching. De-ballasting rig to survival draft - time scale; adequate rig stability during transit and at survival draft. Availability of thrusters to assist in station keeping ability. Mooring tensions: adjustment of moorings to balance tensions during peak loads.


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USER GUIDE TO THE BP XEU DRILLING MANUAL This manual is a GUIDE to drilling, workover and ancillary operations in UK Operations. It is intended as a means of assisting in the conducting of operations more effectively, but must NOT be considered as containing mandatory procedures (hence the change of title to "Guidelines for Drilling Operations"). It contains the recommended procedures and guidelines which may be followed for different operations. Deviation from these procedures should only occur after prior discussion and agreement with the Drilling Superintendent for the rig in advance of an operation being carried out. The manual is a live document and will be updated continuously to reflect changes in technology and new or updated experience. Feedback from you, the manual users, is an essential requirement if the manual is to be accurate and up-to-date. A few sections of the manual are still to be included and will be added as they become available. Suggested changes to the manuals may be made by anyone. However since the manual aims to assist the BP Drill Rep., it is expected that they will be the primary source of the changes. The procedure to be followed in the event of a proposed amendment is to fill out the proforma identifying the section to be changed, why the change is needed, a draft of the replacement section and send it to your Line Manager. Ideally the proposed change should be discussed with the relevant specialist or Drilling Superintendent prior to submission. Once approved the relevant section and index of the manual will be re-issued, pre-punched so that all that is required is to remove the old section/index and insert the replacements. Within the index listings, sections which have been most recently revised, or issued for the first time, are highlighted in bold type to assist in pin-pointing recent changes. Following the index pages in the MST section, a summary is provided on the revisions made to the sections on issue of each subsequent amendment pack.


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PROFORMA FOR UPDATING MANUAL

Date

:

Section to be Changed

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Amendment Proposed By

:

Change Discussed With

:

Brief Summary of Reason for Change:

Draft of New Section:

Send to Line Manager for approval and forwarding to the Well Engineering/ODL Focal Point


SUBJECT:


Safety and Administration. Drilling. Casing and Tubing. Cementing. Drilling Fluids. Wellheads, Packers, Tools and Equipment. Stuck Pipe and Fishing. Well Evaluation. Marine and Miscellaneous.


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Index Prefixes 0000 1000 2000 3000 4000 5000 6000 7000 8000

Section

Master Index and User Guide. General. Semi-Submersible Drilling Units. Jack-Up Drilling Units. Fixed Drilling Units. Forties. Clyde. Beatrice. Magnus. Thistle. Miller. Don. Bruce. Marnock. Ravenspurn. Amethyst. Wytch Farm. Harding.


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Description

0000

SAFETY AND ADMINISTRATION

0120/GEN 0130/GEN 0160/GEN 0300/GEN 0310/GEN 0320/GEN 0400/GEN 0402/GEN 0403/GEN 0405/GEN 0410/GEN 0413/SEM 0415/GEN 0420/FIX 0420/SEM 0440/JAK 0441/JAK 0450/CLY 0450/BEA 0450/MAG 0450/THI 0450/MIL 0450/BRU 0500/FIX 0510/MAG 0510/BRU 0510/AME

H2S (Hydrogen Sulphide) Procedures. CO2 Procedures. Use of Explosives in Drilling Operations. Daily Reports from Rig. Weekly Reports from Rig. General Reports from Rig. Well Control Procedures. Well Control in High Angle or Horizontal Wells. Well Control Whilst Logging. Limited Kick Tolerance. Shallow Gas Procedures. Shallow Gas Procedures (Deepwater in DP Mode). The Effect of Cold Weather on BOP Stacks and Control Lines. Surface BOP Testing - General. Subsea BOP Testing - General. Pressure Testing 21 1/4" BOP. Pressure Testing 13 5/8" BOP. BOP Testing Clyde. BOP Testing Beatrice. BOP Testing Magnus. BOP Testing Thistle. BOP Testing Miller. BOP Testing Bruce. Slot Handover - General. Slot Handover - Magnus. Slot Handover - Bruce. Slot Handover - Amethyst.

Rev.

Date

3 0 2 7 3 7 3 0 0 1 0 0 0 5 0 0 0 4 0 2 0 2 0 1 1 0 0

10/95 04/97 07/91 09/96 09/96 09/96 03/95 05/96 05/96 03/95 07/90 03/91 08/90 09/91 07/90 07/90 07/90 04/91 06/90 11/94 08/90 10/92 05/93 11/89 11/89 03/93 06/94

Sections highlighted in bold are those sections which have been modified (or inserted for the first time) in the most recent amendment to this Guidelines for Drilling Operations. Within each such section, the newly modified parts are identified by the bold black marker line on the right side of the text. A brief resume of the changes is provided at the end of this MST section.


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1000

DRILLING

1000/GEN 1010/GEN 1020/GEN 1050/JAK 1060/SEM 1070/SEM 1100/JAK 1100/SEM 1110/FIX 1130/FIX 1160/CLY 1160/MAG 1160/THI 1160/MIL 1160/BRU 1160/AME 1160/HAR 1200/FIX 1200/SEM 1210/FOR 1210/WYF 1220/BRU 1280/GEN 1300/GEN 1310/GEN 1310/AME 1310/WYF 1320/JAK 1350/GEN 1350/AME 1350/WYF 1400/GEN 1400/AME 1400/WYF 1450/GEN 1500/GEN 1630/GEN 1640/GEN 1660/GEN 1700/GEN 1750/GEN 1800/GEN 1850/SEM

Drilling - General. Depth Referencing. BP Pipe Tally Procedure. Well Establishment - Dril-Quip 3 Well Spacer Template. Well Establishment - Running TGB. Well Establishment - 12 1/4" Pilot Hole. Drilling 36" Hole - Jack-Ups. Drilling 36" Hole - Semi-Submersibles. Conductor Installation - Run/Drill/Run/Cement. Conductor Installation - Drill/Drive. Drilling Top Hole & Running Conductor Clyde. Drilling Top Hole & Running Conductor Magnus. Drilling Top Hole & Running Conductor Thistle. Drilling Top Hole & Running Conductor Miller. Drilling Top Hole & Running Conductor Bruce. Top Hole & Conductor - Amethyst. Drilling Top Hole, Running Conductor and Cementing Harding Drilling Surface Hole - Multi-Well Installations. Drilling 26" Hole - Semi-Submersibles. Drilling 24" Hole Forties. Drilling 24" Hole Wytch Farm. Drilling 24" Hole Bruce. Underreaming in Top Hole. Drilling Vertical 17 1/2" Hole. Drilling Deviated 17 1/2" Hole. Drilling 17 1/2" Surface Hole - Amethyst. Drilling Deviated 17 1/2" Hole Section Wytch Farm. Drilling Deviated 17 1/2" Hole Using Spacer Template. Drilling 12 1/4" Hole. Drilling 12 1/4" Hole - Amethyst. Drilling Deviated 12 1/4" Hole Section Wytch Farm. Drilling 8 1/2" Hole. Drilling 8 1/2" Hole - Amethyst. Drilling Deviated 8 1/2" Hole Wytch Farm. Drilling 6" Hole. Drilling Casing Flotation Equipment with PDC Bits. Mud Motors. Mud Motors Used with MWD Tools. Rebel Tools. Turbodrilling Procedures. Sidetracking Procedures. Suspension and Abandonment Procedures. Wellhead Severance.

Rev.

Date

5 0 2 0 0 0 1 0 1 1 4 1 2 1 0 0 0 1 0 0 1 0 0 1 3 0 1 0 5 0 1 6 0 1 2 2 3 3 0 2 1 1 6

11/90 09/90 11/89 07/90 07/90 07/90 10/90 07/90 12/89 12/89 11/89 11/89 11/89 10/92 05/93 06/94 09/96 02/91 08/90 11/89 04/97 03/93 08/90 12/91 12/91 06/94 04/97 08/90 12/91 06/94 04/97 12/91 06/94 04/97 07/90 12/91 08/90 10/91 10/90 11/89 10/98 12/90 12/90



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Section

Description

2000

CASING AND TUBING

2000/GEN 2005/GEN 2010/GEN 2100/SEM 2100/JAK 2105/FIX 2200/SEM 2200/FIX 2250/CLY 2250/THI 2250/AME 2260/FOR 2260/MAG 2260/BRU 2260/WYF 2300/FIX 2300/SEM 2300/WYF 2350/AME 2400/FIX 2400/SEM 2400/WYF 2450/AME 2500/FIX 2510/GEN 2515/GEN 2520/GEN 2525/GEN 2530/GEN 2535/GEN 2540/GEN 2545/GEN

Prep. & Running Casing - General. Casing Design. Casing Centralisation. Prep. & Running 30" Conductor/PGB - Dril-Quip SS15 System. Prep. & Running 30" Conductor and Stab-In Cement Stinger Assembly. Cutting & Preparation of Casing to Accept Wellhead Spools. Prep. & Run 20"/18 5/8" Casing - Dril-Quip SS15 System. Prep. & Run 20"/18 5/8" Casing - General. Prep. & Run 20" Clyde. Prep. & Run 20" Thistle. Prep. & Run 20" Contingency String - Amethyst. Prep. & Run 18 5/8" Forties. Prep. & Run 18 5/8" Magnus. Prep. & Run 18 5/8" Bruce. Prep. & Run 18 5/8" Casing Wytch Farm. Prep. & Run 13 3/8" Casing. Prep. & Run 13 3/8" Casing - Dril-Quip SS15 System. Prep. & Run 13 3/8" Casing Wytch Farm. Prep. & Run 13 3/8" Casing - Amethyst. Prep. & Run 9 5/8" Casing. Prep. & Run 9 5/8" Casing - Dril-Quip SS15 System. Prep. & Run 9 5/8" Casing Wytch Farm. Prep. & Run 9 5/8" Casing - Amethyst. Prep. & Run 7" Casing. Prep. & Run 7" Baker (Brown) HMC Liner Hanger. Prep. & Run 7" Baker (Brown) HSR Rotating Liner Hanger. Prep. & Run 7" Baker (Brown) HSR Liner Hanger with CPH Packer. Prep. & Run 7" TIW Liner Hanger. Prep. & Run 7" TIW Liner Hanger with Integral Packer. Prep. & Run 7" Nodeco Rotating Liner Hanger with TSP Packer. Prep. & Run 7" Lindsey-Arrow HSB-SC Liner Hanger with WM-P Packer. Prep. & Run 7" Enaco/TIW Rotating Liner Hanger with 'S' Packer and SJ-T Mechanical Rotating Tool. Prep. & Run 4 1/2" Nodeco Rotating Liner Hanger with TSP Packer. Prep. & Run 5 1/2" Nodeco Rotating Liner Hanger with TSP Packer Wytch Farm. Prep. & Run 5" Baker HMC Liner Hanger with CPH Packer. External Casing Patch Operations. Connectors: Hunting Merlin. Connectors: Hunting Lynx. Connectors: Vetco SR-20. Connectors: Vetco ALT Series. Connectors: Vetco RL-4S. BP Standard Casing Data. Tubing Preparation & Running Procedures. Chrome Tubular Handling 13%. Duplex 25% Chrome Tubular Handling/Running Procedure.

2550/GEN 2550/WYF 2560/GEN 2600/GEN 2700/GEN 2705/GEN 2715/GEN 2720/GEN 2725/GEN 2800/GEN 2900/GEN 2950/GEN 2960/GEN

Rev.

Date

4 1 5 4 0 0 4 7 6 2 0 1 1 0 1 5 3 1 0 7 1 1 0 3 5 4 2 4 5 2 1

10/91 10/98 05/92 01/94 07/90 08/91 09/96 10/90 06/92 11/89 06/94 11/89 11/89 03/93 04/97 11/90 12/94 04/97 06/94 01/91 10/90 04/97 06/94 11/90 10/91 10/91 10/91 12/90 12/90 10/91 12/90

0 1

05/96 10/91

1 3 2 1 2 1 1 0 0 0 4 1

04/97 10/91 11/89 12/89 01/94 12/89 12/89 10/90 09/90 08/90 10/98 10/92



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Section

Description

3000

CEMENTING

3000/GEN 3010/GEN 3020/GEN 3030/GEN 3040/GEN 3050/GEN 3100/JAK 3100/FIX 3100/SEM 3100/AME 3200/SEM 3200/FIX 3200/AME 3200/WYF 3210/FIX 3300/GEN 3300/AME 3310/WYF 3350/GEN 3350/AME 3350/WYF 3450/GEN 3450/AME 3500/GEN 3500/AME 3500/WYF

Cementing - General. Cementing - Responsibilities. Cementing - Pre-Job Checklist. Cementing - Operations Checklist. Cementing - Programme Checklist. Cementing - Cement and Additives. 30" Cementation Using Stab-In Technique. 30" Cementation - Fixed Installations Run/Drill/Run/Cement. 30" Conductor and Top-Up Cementations. 30"/27" Conductor Cementation. 20"/18 5/8" Cementation. 20"/18 5/8" Cementation Using Stab-In Technique. 20" Cementation Using Stab-In Technique - Amethyst. 18 5/8" Cementation using an Inner String Method Wytch Farm. 20"/18 5/8" Cementation Using a Casing Pack-Off. 13 3/8" Cementation. 13 3/8" Cementation - Amethyst. 13 3/8" Cementation using an Inner String Method Wytch Farm. 9 5/8" Cementation. 9 5/8" Cementation - Amethyst. 9 5/8" Two Stage Cementation Wytch Farm. 7" Liner Cementation and Clean-Out. 7" Liner Cementation and Clean-Out - Amethyst. 5"/4 1/2" Liner Cementation and Clean-Out. 4 1/2" Liner Cementation and Clean-Out - Amethyst. 5 1/2" Liner Cementation and Displacement of Liner and 9 5/8" Wytch Farm. Liner Cement Cleanout Wytch Farm. Post Perforation Cleanout Wytch Farm. Liner Pressure Testing. Liner Drawdown Testing. Cement Plugs. Parabow Cementing Tool. Squeeze Cementing. Losses During Cementation. Cement Contaminated Oil Based Mud. Evaluation of Primary Cementing.

3510/WYF 3520/WYF 3550/GEN 3560/GEN 3600/GEN 3610/GEN 3650/GEN 3750/GEN 3780/GEN 3800/GEN

Section

Rev.

Date

2 2 2 1 1 2 1 1 1 0 0 2 0 1 1 2 0 1 2 0 1 4 0 3 0

08/91 08/91 08/91 11/89 11/89 03/91 11/89 07/91 01/94 06/94 07/90 11/89 06/94 04/97 11/89 07/90 06/94 04/97 07/90 06/94 04/97 03/91 06/94 03/91 06/94

1 1 1 2 2 7 0 2 0 0 3

04/97 04/97 04/97 07/90 07/90 05/96 05/96 07/90 07/90 08/90 10/90



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Section

Description

4000

DRILLING FLUIDS

4000/GEN 4100/GEN 4110/GEN 4120/GEN 4130/GEN 4140/GEN 4150/GEN 4160/GEN 4170/GEN 4200/GEN 4250/GEN 4300/GEN 4400/GEN 4500/GEN 4600/GEN 4800/CLY 4800/BEA 4800/MIL 4900/GEN

Drilling Fluids - General. Spud Mud. Prehydrated Bentonite Premix. Bentonite Polymer Mud. Gypsum/Polymer Mud. Seawater Polymer Mud. KCl Polymer Mud. Inverse Oil Emulsion Mud. Salt Saturated Mud. Barytes Plug - Water Based Mud. Barytes Plug - Oil Based Mud. Lost Circulation. Contamination of Drilling Fluids. Mud Testing. Solids Control. Pit System Clyde. Pit System Beatrice. Pit System Miller. Drilling Hydraulics.

Rev.

Date

2 2 2 2 2 2 2 3 2 2 2 2 2 2 2 0 0 0 1

11/89 11/89 11/89 11/89 11/89 11/89 11/89 08/90 11/89 11/89 11/89 11/89 11/89 11/89 11/89 08/91 05/92 12/91 09/91



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Section

Description

5000

WELLHEADS, PACKERS, TOOLS & EQUIPMENT

5010/SEM 5030/JAK 5035/JAK 5050/FOR 5050/CLY 5050/MAG 5050/BRU 5050/AME 5050/WYF 5051/FOR 5200/GEN 5205/GEN 5210/GEN 5215/GEN 5220/GEN 5225/GEN 5227/GEN 5230/GEN 5235/GEN 5237/GEN 5400/GEN 5410/GEN 5420/GEN 5440/GEN 5460/GEN 5500/SEM

Subsea Guideline Wellhead Systems - General. Mudline Suspension Systems. Prep. & Run PLEXUS "CENTRIC 15", Mudline Suspension System. Wellhead System Forties FA/FC. Wellhead System Clyde. Wellhead System Magnus. Wellhead System Bruce. Wellhead System Amethyst. Wellhead System Wytch Farm. Wellhead System Forties FB/FD. Packers: Baker (Brown) JM Compression Set Tie-Back Packer. Packers: Baker (Brown) CPH Hydraulic Set Tie-Back Packer. Packers: TIW SN-6 Retrievable Tie-Back Packer. Packers: Bridge Plug Setting General. Packers: EZ-Drill-SV Squeeze Packer. Packers: Bobcat Retrievable Bridge Plug. Packers: Arrow DLT Packer, Unloader and Storm Valve. Packers: Johnson Hurricane Packer. Packers: Halliburton RTTS Packer. Packers: BJ Services Mode 1223 Packer. Drilling Jars. Hydril Retrievable Drop-In Check Valves. Drill Stem Circulating Subs. Bypass Valves. Drill String Lifting and Handling Equipment. Heave Compensation Systems.

Rev.

Date

2 0 0 2 5 2 0 0 1 2 3 3 3 3 2 2 0 3 2 0 0 0 0 0 0 1

08/94 08/90 04/91 07/90 12/91 01/91 05/93 06/94 04/97 07/90 07/90 07/90 07/90 11/89 11/89 11/89 05/96 07/90 11/89 10/95 08/90 08/90 08/90 08/90 07/90 07/90



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Section

Description

6000

STUCK PIPE AND FISHING

6000/GEN 6005/GEN 6010/GEN 6020/GEN 6050/GEN 6100/GEN 6150/GEN 6200/GEN 6250/GEN 6400/GEN 6410/GEN 6420/GEN 6430/SEM 6500/GEN

Stuck Pipe Prevention and Procedures. Calculation of Optimum Fishing Time. Freeing Differentially Stuck Pipe Using the “U”-Tube Method. Freeing Stuck Pipe Whilst Drilling Riserless and From Fixed Installations. Jar Placement and Jarring Practices. Effective Pull on Stuck Pipe. Free Point Determination and Back-Off Procedures. Fishing - Procedures and Tools. Stuck Logging Tools. Packer Milling and Retrieval. Casing Milling. Section Milling. Casing Milling and Underreaming for Open Hole Gravel Pack. Bit Nozzle Removal.

Rev.

Date

2 0 0 0 0 3 5 7 5 1 2 1 0 2

01/91 04/91 07/90 01/91 09/90 09/90 10/92 11/94 08/94 11/89 04/97 04/97 09/92 11/89



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Section

Description

7000

WELL EVALUATION

7005/GEN

Loading, Setting, Timing and Operation of Dropped Survey Barrel Equipment. Leak-Off Testing. Coring. Oriented Coring. Extra Long Core Barrel. Mud Logging Services. Electric Logging Operations Using Pressure Equipment.

7100/GEN 7200/GEN 7210/GEN 7220/GEN 7300/GEN 7400/GEN

Rev.

Date

0 4 3 3 4 2 2

04/91 06/90 08/90 08/90 11/89 11/89 11/89



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Section

Description

8000

MARINE AND MISCELLANEOUS

8150/JAK 8160/JAK 8200/JAK 8300/SEM 8410/WYF 8420/WYF

Positioning Self-Elevating Jack-Up Rigs Alongside a Fixed Structure. Pulling Away From Fixed Structures. Jacking Procedures. Heavy Weather Policy - General. Formation Saver Valve Installation Procedure Wytch Farm. ESP Completion Running Procedure Wytch Farm.

Rev.

Date

3 2 2 0 0 0

11/90 09/90 09/90 10/90 04/97 04/97



BP EXPLORATION

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REVISION HISTORY AMENDMENT NO. 6 (6/94) Section

New Revision No.

Remarks

0510/AME 1160/AME 1310/AME 1350/AME 1400/AME 2250/AME 2350/AME 2450/AME 3100/AME 3200/AME 3300/AME 3350/AME 3450/AME 3500/AME 5050/AME

0

First issue of all sections specific to Amethyst

0101/GEN

HSE Policy removed

Now available in WEO Policies & Strategies Handbook (WEO-W23)

0102/GEN

Well Plugging Policy removed


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AMENDMENT NO. 7 (8/94) Section

New Revision No.

Remarks

MST

7

Inclusion of revision history.

0300/GEN

5

Major revision of all sub-sections, removing IDDS report formats, and repositioning fluids reporting.

0310/GEN

1

Major revision to weekly equipment status reporting.

0320/GEN

4

Major revision of most sub-sections; removal of close-out inventory report, and insertion of end-of-well chemical usage reports.

3600/GEN

6

Addition of extra warning of danger of U-tubing of cuttings/debris whilst running cement stinger.

5010/SEM

2

Addition of extra warning of danger of release of gas trapped beneath pack-off on retrieval of same.

6250/GEN

5

Additional warning of damage of birds-nesting of cable whilst running a fishing string to recover wireline fish.


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New Revision No.

Remarks

MST

8

Inclusion of further amendments.

0400/GEN

2

Much revised and reduced, as such details are included within the separate manual "Well Incident Immediate Response Plan" (WEO-W20), particularly as they apply to all well operations, not only drilling.

0450/MAG

2

Re-write of Sections 2.1 and 3.9 to reflect current offshore practice whilst testing the BOP stack. Re-write of Sections 4 and 5, expanding diverter procedures, and amending them to address the burst disc rather than the ball valve rig-up.

6200/GEN

7

Amendment to guidance on page 7 concerning use of extension sub whilst using an overshot.


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New Revision No.

Remarks

MST

9


0320/GEN

5

Amendment to sub-sections 17 - 20, Reporting for Mud and Cement Chemical Usage, and the addition of reference to WEOW07, Section 3, which contains further guidance and examples of completed forms.

0600/GEN

-

Removal of section, as there is now sufficient stock reporting (as per 0300, 0310 and 0320/GEN) to satisfy material consumption reports used by Andersens for accounts purposes.

2300/SEM

3

Modification of the special considerations section, as there is no longer a requirement to use specially dimensioned slips and elevators.


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New Revision No.

Remarks

MST

10

Inclusion of further amendments, plus clarifying the positioning of the manual as GUIDELINES only.

0400/GEN

3

Correction of references to the new "Well Incident Response Procedures" manual.

0405/GEN

1

Correction of reporting of Kick Tolerance and the corrected reference to location of details concerning the determination of Limited Kick Tolerance.

2005/GEN

0

Summary and Quick Guide to full BPX Casing Design manual. The portion repeated here is to allow more staff to access information on the design of casing, and the application of safety factors.

8400/GEN

-

Removal of section which addresses Diving Operations, as the text of this section does NOT reflect the manner in which diving contracts are now arranged and managed, e.g. contrary to the original text of the section, the BP Drilling Rep. or Supervisor is NOT the same person as the Diving Supervisor.


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New Revision No.

Remarks

MST

11


0300/GEN 0310/GEN 0320/GEN

6 2 6

0320/GEN

6

Correct identification of the supplier of specific distribution lists for the majority of reports to be submitted (PSR Manpower Services Co-ordinator).

0320/GEN

6

The frequent references to CSON reports have been modified, identifying the correct PON (Petroleum Operations Notice) report number in its place.

0320/GEN

6

Complete revision of sub-section 4 (Accident Reporting) to take account of the replacement of the CARE database with the LOCOS (LOss COntrol System). This includes the replacement of the ‘Orange’ reports with the white and yellow ‘Investigation Report’, the white part to be completed on site, and the yellow to be completed onshore, and entered into the centrally held LOCOS Database.

8100/GEN 8120/GEN 8200/GEN

-

Removal of each section, as their contents were no longer correct. The equivalent (but correct) subject matter is now contained within another manual, the ‘Standing Instruction and Guidelines for Offshore Marine Operations’

1210/WYF 1310/WYF 1350/WYF 1400/WYF 2260/WYF 2300/WYF 2400/WYF 2550/WYF 3200/WYF 3310/WYF 3350/WYF 3500/WYF 3510/WYF 3520/WYF 5050/WYF

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Reports which specify the submission of a Telex have been modified to refer to E-mail and/or Fax reports instead.

New sections specific to Wytch Farm operations.

There have also been changes made to page headings etc to reflect the change in title of the manual, emphasising the fact that it contains GUIDELINES, and that its reference number is now PSR-W06.


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New Revision No.

Remarks

MST

12


0120/GEN

3

Update of several sections of these guidelines, most importantly where a list of contractors and other relevant contacts is provided.

5237/GEN

0

Inclusion of a new section concerning the use of BJ model 1223 packers, as these may also be used as hurricane packers instead of the more common Halliburton RTTS packer, or the Johnson Hurricane Packer, details of which are contained in sections 5230/GEN and 5235/GEN

Harding-specific sections will be issued with the next revision to these Drilling Guidelines.


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New Revision No.

Remarks

MST

13


0402/GEN

0

These guidelines have been issued previously, although in a different form.

0403/GEN

0

These guidelines were originally produced by the Miller team, but are equally applicable to all Asset Wells teams.

2545/GEN

0

This type of rotating liner hanger is in common use with the SNS Asset, although it may be suitable for use in other areas.

3600/GEN

7

The rewrite takes account of learning as a result of experience over the last 3 years and plug setting in high angle wells. It also details new equipment for improved plug setting. All three cement companies have had input and the opportunity to transfer their own learning.

3610/GEN

0

First issue of guidelines for use of Parabow Cementing Tool whilst setting balanced cement plugs.

5227/GEN

0

First issue of guide for the use of Arrow products - their DLT Packer, Unloader and Storm Valve.

Harding-specific sections will be issued with the next revision to these Drilling Guidelines.


SUBJECT:


Section

:

MST

Rev.

:

17 (10/98)

Page

:

21 of 24



New Revision No.

Remarks

MST

14


0300/GEN

7

Text removed. Refer to PSR-W28.

0310/GEN

3


0320/GEN

7


1160/HAR

0

New section

2200/SEM

4

Alternative lockdown method added.


SUBJECT:


Section

:

MST

Rev.

:

17 (10/98)

Page

:

22 of 24



New Revision No.

Remarks

MST

15


0130/GEN

0

New section

1210/WYF

1

Updated to better reflect current practices.

1310/WYF

1


1350/WYF

1


1400/WYF

1


2260/WYF

1


2300/WYF

1


2400/WYF

1


2550/WYF

1


3200/WYF

1


3310/WYF

1


3350/WYF

1


3500/WYF

1


3510/WYF

1


3520/WYF

1


5050/WYF

1


6410/GEN

2


6420/GEN

1


8410/WYF

0

New section

8420/WYF

0

New section


SUBJECT:


Section

:

MST

Rev.

:

17 (10/98)

Page

:

23 of 24



New Revision No.

Remarks

MST

16

Inclusion of new amendment.

2950/GEN

3

Update of information in Para 2 ‘Transportation’.


SUBJECT:


Section

:

MST

Rev.

:

17 (10/98)

Page

:

24 of 24



New Revision No.

Remarks

MST

17

Inclusion of new amendment.

1750/GEN

1

Total replacement of section.

2005/GEN

1

Removal of old version, replaced with a reference to the BPX Casing Design Manual.

2950/GEN

4

Removal of reference to old 1992/3 contracts.

BP Drilling Manual

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