ENI - Well Control Policy Manual

ARPO

ORGANISING DEPARTMENT

ENI S.p.A. Agip Division

TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REFER TO SECTION N.

OF

STAP

P

1

M

1

PAGE.

92

6150

TITLE WELL CONTROL POLICY MANUAL

DISTRIBUTION LIST Eni - Agip Division Italian Districts Eni - Agip Division Affiliated Companies Eni - Agip Division Headquarter Drilling & Completion Units STAP Archive Eni - Agip Division Headquarter Subsurface Geology Units Eni - Agip Division Headquarter Reservoir Units Eni - Agip Division Headquarter Coordination Units for Italian Activities Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CDRom version can also be distributed (requests will be addressed to STAP Dept. in Eni Agip Division Headquarter)

Date of issue:

28/06/99

„ ƒ ‚ • € Issued by

REVISIONS

P. Magarini E. Monaci 28/06/99

C. Lanzetta

A. Galletta

28/06/99

28/06/99

PREP'D

CHK'D

APPR'D

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given

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REVISION STAP-P-1-M-6150

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INDEX

1.

2.

3.

4.

5.

INTRODUCTION

6

1.1.

Purpose of the manual

6

1.2.

UPDATING, AMENDMENT, CONTROL & DEROGATION

7

1.3.

DRILLING CONTRACTOR'S PERSONNEL

7

1.4.

SAFETY TARGETS 1.4.1. Primary Control 1.4.2. Secondary Control

8 8 8

1.5.

TECHNICAL PROFICIENCY

8

COMPREHENSIVE WELL CONTROL PROCEDURES

9

2.1.

PRIMARY WELL CONTROL 2.1.1. Drilling Programme 2.1.2. Detection OF Abnormal Well Conditions 2.1.3. Kick Prevention 2.1.4. Maximum Allowable Annulus Surface Pressure (MAASP) 2.1.5. Reduced Pump Stroke Pressure (RPSP)

9 9 9 10 11 11

2.2.

SECONDARY WELL CONTROL 2.2.1. Kick Control Procedures (Preliminary Actions) 2.2.2. Kick Detection Procedure While Drilling 2.2.3. Kick Detection Procedure While Tripping

12 12 12 12

SHUT-IN PROCEDURE.

14

3.1.

SOFT SHUT IN PROCEDURE (for LAND RIGS, JACK UPS AND FIXED PLATFORM) 3.1.1. Soft Shut-in Procedure While Drilling 3.1.2. Soft Shut-in Procedure While Tripping

14 14 15

3.2.

SOFT SHUT IN PROCEDURE (Floaters) 3.2.1. Soft Shut-in Procedure While Drilling 3.2.2. Soft Shut-in Procedure While Tripping

16 16 17

3.3.

POST Shut-In OPERATIONS

18

3.4.

PRESSURE DATA RECORDING

18

STRIPPING PROCEDURE

19

4.1.

OFF BOTTOM KICKS 4.1.1. Preparing To Strip-In

19 19

4.2.

STRIPPING METHODS 4.2.1. Stripping Through Annular Preventers 4.2.2. Stripping Through Ram Preventers 4.2.3. Annulus pressure control while stripping 4.2.4. Stripping Worksheet

20 21 21 22 23

KILLING PROCEDURES

24

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5.1.

Well Control Methods 5.1.1. Wait And Weight Method 5.1.2. Driller’s Method 5.1.3. Volumetric Method 5.1.4. Volumetric control worksheet 5.1.5. Bullheading

24 24 26 27 29 30

5.2.

horizontal well considerations

30

5.3.

FLOATING RIG CONSIDERATIONS 5.3.1. Effect Of Choke Line Length 5.3.2. Influx Removal From BOP And Riser

31 31 32

EQUIPMENT REQUIREMENTS

35

6.1.

BOP STACK SYSTEMS 6.1.1. Land Rigs, Jack-Ups And Fixed Platform 6.1.2. Floating Rigs

35 35 36

6.2.

BOP CONTROL SYSTEM 6.2.1. Land Rigs, Jack-Ups And Fixed Platform 6.2.2. Floating Rigs

37 37 38

6.3.

CHOKE MANIFOLD

39

6.4.

INSIDE PIPE SHUT-OFF DEVICES

39

6.5.

MUD GAS SEPARATOR

40

6.6.

diverter equipment

40

6.7.

AUXILIARY EQUIPMENT

42

CASING AND BOP EQUIPMENT TESTS

43

7.1.

GENERAL PROCEDURES 7.1.1. Test Recording

43 43

7.2.

BOP EQUIPMENT TESTS 7.2.1. Land, Jack-Ups And Fixed Platforms BOP Pre-Deployment Tests 7.2.2. BOP Tests After Installation 7.2.3. Surface BOP Testing Procedures

44 44 44 44

7.3.

FLOATing RigS 7.3.1. BOP Tests During And After Installation 7.3.2. BOP And Seal Assembly Tests After Setting Casing 7.3.3. Routine BOP Tests While Drilling 7.3.4. Routine Subsea BOP Testing Procedures

45 45 45 46 46

7.4.

bOP TESTing frequency 7.4.1. BOP Test Durations 7.4.2. BOP Function Tests 7.4.3. BOP Operating Equipment Tests 7.4.4. Kill lines, Choke Lines And Choke Manifold Tests 7.4.5. IBOP, Cementing Manifold, Pumps And Standpipe Manifold Tests

46 46 47 47 47 47

7.5.

Casing Tests

48

7.6.

OTHER TESTS WHILE DRILLING

48

BLOW-OUT PREVENTION DRILLS

49

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8.1.

FAMILIARITY DRILLS 8.1.1. Shut-In Drills 8.1.2. Choke Manipulation Drill

49 49 50

8.2.

EMERGENCY ‘ON-THE-RIG’ DRILLS 8.2.1. Potential Fire On Well And Rig Abandonment Simulation 8.2.2. H2S Drill 8.2.3. Abandon Rig

50 50 50 51

8.3.

WELL CONTROL DRILLS 8.3.1. Pit Drills 8.3.2. Trip Drills 8.3.3. Trip Drill With Drillpipe In The BOP Stack. 8.3.4. Trip Drill With Drill Collar Or Tubing In The BOP Stack.

51 51 52 52 52

8.4.

Accumulator Drills

53

8.5.

Diverter Drills

53

8.6.

Drill FREQUENCY AND Response TIMES 8.6.1. Drill Frequency 8.6.2. Timing

54 54 55

SHALLOW GAS

56

9.1.

SHALLOW GAS INVESTIGATION

56

9.2.

PRIMARY WELL CONTROL

57

9.3.

RECOMMENDED DRILLING PRACTICES 9.3.1. General Practices 9.3.2. Logging 9.3.3. Losses 9.3.4. Cementing Operations 9.3.5. Drilling Procedures

57 57 59 59 59 60

9.4.

DIVERTER SYSTEM OPERATIng PROCEDURES 9.4.1. Diverter System 9.4.2. Diverter Test (before start of operations) 9.4.3. Diverter Procedure

61 62 64 64

10. H2S DRILLING PROCEDURES

65

10.1. Emergency Safety Plan

65

10.2. DUTIES OF PERSONNEL 10.2.1. Manager Or OIM 10.2.2. All Personnel 10.2.3. Eni-Agip Drilling Supervisor 10.2.4. Drilling Contractor's Toolpusher 10.2.5. Driller 10.2.6. Mud Engineer

66 66 66 66 67 67 67

10.3. OPERATING CONDITIONS AND PROCEDURES 10.3.1. Condition 1 - Pre Alarm 10.3.2. Condition 2 - Alarm 10.3.3. Core Recovery In Presence Of H2s 10.3.4. Well testing in presence of H2S

67 67 69 70 70

10.4. Emergency Condition 10.4.1. Emergency Operating procedure

73 74

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10.5. ACTIONS TO TAKE FOR THE CONTROL OF AN EMERGENCY

75

10.6. EMERGENCY TEAM

75

10.7. DELIMITATION OF THE POLLUTED AREA (onshore)

76

10.8. PERSONNEL TRAINING 10.8.1. Safety Meeting

76 76

10.9. H2S Prevention drills 10.9.1. Alarm Drills 10.9.2. Emergency Drills 10.9.3. Drill Frequency

77 77 78 78

10.10. H2S DETECTION SYSTEM 10.10.1. H2S detection in air 10.10.2. Sensor Ranges

78 78 79

10.11. BREATHING APPARATUS AVAILABILITY 10.11.1. Standard Equipment For All Rigs

80 80

10.12. CASCADE SYSTEM

81

10.13. USE OF BREATHING APPARATUS

82

10.14. ADDITIONAL safety features

82

10.15. INSPECTION/MAINTENANCE OF DETECTION/PROTECTION SYSTEMS

83

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INTRODUCTION This document replaces: STAP P 1 M 071 - WELL CONTROL POLICY FOR LAND DRILLING UNITS (Chapter 7 of ‘General Drilling Procedures for Land Drilling Units’) STAP P 1 M 6033 - WELL CONTROL POLICY FOR JACK UP AND FIXED PLATFORM (Chapter 13 of ‘General Drilling Procedures for Self Elevating Mobile Offshore Drilling Units - Jack Up - and Fixed Platform’) STAP P 1 M 047 - WELL CONTROL POLICY FOR FLOATER (Chapter 38 of ‘General Drilling Procedures for Floating Drilling Unit’)

1.1.

STAP P 1 M 11 -

SHALLOW GAS DRILLING GUIDELINE

P 1 M 6035 -

DRILLING PROCEDURES FOR OFFSHORE WELLS IN H2S ENVIRONMENT

P 1 M 6039 -

DRILLING PROCEDURE FOR LAND WELLS IN THE PRESENCE OF H2S

PURPOSE OF THE MANUAL The main purpose of this Well Control Policy is to make all parties, involved in Eni-Agip Division and Affiliates drilling and completion activities world-wide, aware of the Company’s basic rules and procedures related to Well Control Policy issues. Nevertheless, the policies in this manual, while being compulsory, cannot foresee all aspects of the operations that may be encountered on the well site. It consequently requires oneself to conform to the principles of this policy in dealing with unexpected situations different from those planned or anticipated. Such Corporate Standards define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the Corporate Company Principles. This, however, still enables each individual Affiliated Company the capability to operate according to local laws or particular environmental situations. Company regulations and/or Petroleum Industry world-wide accepted practices do not substitute for government regulations, nor is it possible to include all of the issued governmental regulations inside one Company general policy statement. Part of the duty of Company drilling personnel operating world-wide, includes verification that actual Company policy meets with any and all local regulations, ensuring that the most stringent of the policies or regulations between both apply. The Drilling Contractor will issue their own ‘Operating Practices and Emergency Procedures’ which shall be applicable to the Drilling Contractor's rig and equipment specifications and to meet with the intent of Eni-Agip’s Well Control Policies. The Drilling Contractor’s ‘Operating Practices and Emergency Procedures’ shall be submitted to, and approved by, the Company before the contract commences. For floating rigs, details have to be provided of the marine riser tensioning and the practical operating motion limits of the rig, beyond which drilling, tripping, handling BOP and testing shall be suspended.

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UPDATING, AMENDMENT, CONTROL & DEROGATION This is a ‘live’ controlled document and, as such, it will only be amended and improved by the Corporate Company, in accordance with the development of Eni-Agip Division and Affiliates operational experience. Accordingly, it will be the responsibility of everyone concerned in the use and application of this manual to review the policies and related procedures on an ongoing basis. Locally dictated derogations from the manual shall be approved solely in writing by the Manager of the local Drilling and Completion Department (D&C Dept.) after the District/Affiliate Manager and the Corporate Drilling & Completion Standards Department in Eni-Agip Division Head Office have been advised in writing. The Corporate Drilling & Completion Standards Department will consider such approved derogations for future amendments and improvements of the manual, when the updating of the document will be advisable.

1.3.

DRILLING CONTRACTOR'S PERSONNEL As clearly stated in Eni-Agip’s Contracts, all Drilling Contractor personnel shall be proven to be competent and able to act with diligence in a safe and workmanlike manner according to good Oilfield Practices. Within the terms of the Well Control Policy, this means that each crew shall be completely familiar with the installation, operation, care and maintenance of every item of equipment with regard to the mud system, trip tank, surface and choke manifold, mud/gas separators, valves, instruments, pressure gauges, indicators, volume meter, BOP’s and their operating units. Key personnel such as Rig Managers, Toolpushers, Tourpushers, Drillers, Assistant Drillers, Subsea Engineers shall have the fundamental theoretical knowledge on kick and blow-out control techniques and also hold a current Well Control Certificate issued by an accredited industry training institute recognised by Governmental bodies and the Company. Furthermore, it is required that each member should be familiar with every item of equipment used in well control. The minimum personnel knowledge and capabilities required for a crew member to be considered competent is: • • • •

To have sufficient knowledge of all the equipment in order to be able to determine when operating functions are not working properly, and consequently, take all necessary remedial actions to reinstate full functionality. To have sufficient knowledge of operating procedures in order to be able to react in due time, understanding completely what is occurring. To be able to correctly interpret the various abnormal situations and take the appropriate remedial steps of action. Carry out basic calculations, and use the results in order to safely manage any occurrences.

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SAFETY TARGETS Maintaining the well under full control at all the times shall be the main safety target. This is to be achieved by applying appropriate principles and techniques aimed at providing the following well control phases:

1.4.1.

Primary Control During drilling operations, a mud hydrostatic pressure will be used to exceed or overbalance the formation pressure and prevent the formation fluids from being able to enter the wellbore.

1.4.2.

Secondary Control When primary well control has been lost or compromised and formation fluid enters the wellbore, the blow-out prevention equipment and procedures will be brought into action in order to re-establish primary control and safe operating conditions.

1.5.

TECHNICAL PROFICIENCY The primary concern of all parties involved in drilling hydrocarbon wells is to maintain full control of formation fluids at all times, preventing their migration into the wellbore. When occasions do occur when formation fluids enter the wellbore, proper actions must be implemented to control the influx and restore safe operating conditions. The basic rules, practices and techniques used to achieve these goals are found from: • • • • • • •

Well Control Policies. Local regulations. Drilling programme. Operational rules and emergency procedures. Methods and means to permit an early detection of abnormal situation. Inspections, tests and maintenance of prevention equipment. Personnel theoretical knowledge, training and skill.

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2.

COMPREHENSIVE WELL CONTROL PROCEDURES

2.1.

PRIMARY WELL CONTROL

2.1.1.

Drilling Programme Primary well control is at first achieved by the implementation of a properly prepared drilling programme, based on pore pressure predictions ( Refer to the Overpressure Evaluation Manual). This information should allow the proposed well targets being reached, protecting personnel, rig equipment and Company assets. The Company shall provide data and information derived from: • • •

Wells previously drilled in the same field or in the same area Seismic surveys Geological information

This data shall be analysed in order that an appropriate drilling programme can be compiled. The Drilling Contractor shall receive a copy of the drilling programme in advance so as to be ready to make rig personnel familiar and acquainted with the risks of the variant well drilling operations involved. Primary well control depends mainly on the use of correct mud weights, proper operating practices implemented, as well as the accuracy and control of constantly gathered data; These data should be correctly interpreted and timely reported. ‘Drilling for kicks’ is not permitted, i.e. ‘underbalance’ drilling operations and definitely never allowed on wildcats under any circumstances. Underbalance drilling shall only be allowed after approval by the Company Drilling Manager through the implementation of an authorised detailed drilling programme or other written instructions. The casing point, type of casing to be run in hole (grade, weight and coupling), types of preventers and their working pressure, will be selected in accordance to the predicted pressure profile, planned mud weight and required safety margins. 2.1.2.

Detection OF Abnormal Well Conditions Qualitative and quantitative methods have been developed for accurate detection of any abnormal conditions occurring while drilling (refer to the ‘Drilling Procedures Manual’). Generally these methods are subdivided into the following groups: • •

•

Use of previous field history and drilling experiences (depth of flowing zones, pore and fracture gradients, types of fluids, permeability, mud losses and lost circulation intervals). Physical responses from the well (pit gains or losses, increases in drilling fluid return rates, changes in flowing temperatures, drilling breaks, variations in pump speeds and/or standpipe pressures, swabbing, reduction in mud densities, effects on gas shows and pit gains due to pipe connections, short and round trips, hole problems indicating underbalance). Chemical and other responses from the well (chloride changes in the drilling fluid, oil and gas shows, formation water, shale density, electrical logs, drilling parameters equations and MWD/LWD readings).

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Kick Prevention If primary control is lost a kick will be experienced. Common causes of kicks are: • • • • •

Swabbing in of formation fluids while tripping. Failure to check that the hole takes or gives up the correct volume of fluid when tripping. Encountering abnormal formation pressure. Having insufficient mud weight. Loss of circulation leading to reduction in hydrostatic pressure.

It is the responsibility of the Drilling Contractor to keep the hole full at all times by using all the available equipment. The Drilling and Completion Supervisor shall monitor that the correct preventive practices are being implemented and/or conducted at all times. Extreme care shall be taken to monitor mud volume, drilling breaks and gas cut mud. Mud Volume Control (trip volume/active volume control) Starting with the principle that it is the ‘Drilling Contractor’s responsibility to keep the hole full of the proper drilling fluid at all times’ through the use of monitoring devices and visual observation, the Drilling Contractor’s crew shall continuously check the following: • •

While tripping, the well takes or returns the correct amount of drilling fluids according to drill pipe displacement. While drilling, the drilling fluids level in the circulating mud tanks alters in accordance with the mud chemical treatment and/or penetration rate.

Quick detection of any change in the monitored well parameters, allows fast reactions to be taken aimed at a timely solution of problems, therefore: a)

While drilling: • •

b)

Pit level rising, indicates that formation fluid is entering the wellbore. Pit level falling, means that the mud pumped is being taken by the formation. In the case of the mud level dropping in the annulus, the pressure exerted by the mud column decreases and consequently formation fluids may enter the borehole.

While tripping in and out of hole: •

The piston effect occurring between the drill pipe and the hole may lead to either surge or swab pressures acting on the formation. In both cases, variations in hydrostatic pressure may cause the well to kick, even if the correct mud weight is being used.

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Drilling Break Any time a drilling break is noticed, drilling shall stop (ensure no more than 1.5m or 5ft is applied into the break) and a static monitoring of the well shall be carried out. • •

If the well is static, the Company Wellsite Drilling and Completion Supervisor will decide whether to circulate bottoms up or resume drilling. If the well is flowing, the correct shut-in procedure will be implemented as quickly as possible.

Gas Cut Mud Gas cut mud may be a possible warning of taking a kick, so investigation of pore pressure should be made when background gas and pipe connection gas is higher than normal. With the presence of recurring pipe connection gas, and increasing background gas, a short trip should be made before pulling out of the hole, especially in over-pressured zones. 2.1.4.

Maximum Allowable Annulus Surface Pressure (MAASP) For each phase of drilling, the MAASP value depends on the following factors: • • •

Mud weight. Minimum formation fracture gradient below the shoe. Minimum casing burst resistance on the last casing string.

The MAASP shall be defined by the Company's Wellsite Drilling and Completion Supervisor, either after setting each new casing string or whenever the density of the drilling mud changes. The MAASP value of fracture gradient at every casing shoe depth shall be, either, stated in the drilling programme or derived from a leak-off test. In order to avoid casing burst or formation breakdown during well control operations, the MAASP shall be clearly written on a Kick Control sheet which will be posted near the choke control panel. 2.1.5.

Reduced Pump Stroke Pressure (RPSP) The Driller is responsible for carefully measuring and recording the RPSP. The normal circulation flowrate shall be reduced approximately to 1/3 in 121/4" and larger hole sections and 1 /2 in 81/2" hole sections. Awareness of these values is an important element in killing operations, in order to avoid formation breakdown. RPSP must be taken at the following times as a minimum: • • •

Once per tour, or every 300m (1,000ft) intervals. When there is any significant changes in the mud weight or mud properties. Whenever changes occur in the dimension and characteristics of the string, i.e. change in BHA, jet size, jet plugged or jet lost, etc.

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On floater rigs, the RPSP shall be measured by circulating, first through the riser and then through the choke/kill line. If circulating through the choke manifold, the adjustable choke must be completely open. On wells in deep water, at least two or more reduced circulating rates, pressures and corresponding choke line pressure losses should be recorded plus the pressure losses through both lines used in parallel. The RPSP pressures must be measured on the choke control panel gauge or on the gauge which would be used during well control operations and recorded on the IADC report. 2.2.

SECONDARY WELL CONTROL The first indication of a kick may be one of the following: • • • • • • •

2.2.1.

A pit gain. A drilling break. Increased flow across the flow line and shakers. Gas or water cut mud returns. A drop in pump pressure or increase in pump strokes. Swabbing on trips (the well is not taking the right amount of mud to compensate for pipe volume). A total loss of circulation.

Kick Control Procedures (Preliminary Actions) If there is an indication of a possible kick occurring, the Driller shall follow the kick detection procedures outlined below.

2.2.2.

Kick Detection Procedure While Drilling 1)

2)

Stop drilling. With the pump on, pick up kelly or top drive to a predetermined position, i.e. with the tool joint clear of the preventer sealing element (and with the lower kelly cock above the rig floor when drilling with a kelly). Shut off the pumps and check for well flow by visual examination on the bell nipple or flow line. a) If the well is not flowing: • •

2.2.3.

Immediately notify the Company Wellsite Drilling and Completion Supervisor and Drilling Contractor Toolpusher. The Company Wellsite Drilling and Completion Supervisor will decide whether to circulate bottoms up or resume drilling. The penetration rate will be limited as long as the cause of the abnormal situation is undetermined. Always be aware that some hydrocarbons (gas or oil cut mud) may rise to the surface. Ensure that the proper monitoring and safety systems all in place.

b)

If the well is flowing:

• •

Close the well as per the ‘Shut-in Procedure’ (refer to section 3). Immediately notify the Company Wellsite Drilling and Completion Supervisor and Drilling Contractor Toolpusher.

Kick Detection Procedure While Tripping

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stop tripping, install a full opening safety valve (lower kelly cock). fill up the hole if required, and check for flow. a) If the well is not flowing: • •

If no indications of swabbing or incorrect filling have been observed resume tripping with extreme care. If swabbing while tripping out is observed: run back to bottom, circulate bottoms up, check for samples and consistency, increase mud weight or condition mud, if required, resume tripping with extreme care, it may be necessary to pump out pipe.

b)

If the well is flowing:

• •

Close the well as per the ‘Shut-In Procedure’. Immediately notify the Company Wellsite Drilling and Completion Supervisor and Drilling Contractor Toolpusher.

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SHUT-IN PROCEDURE. Eni-Agip’s standard well shut-in procedure is the Soft Shut-In Procedure, unless local legislation or third party contractor’s accepted procedures dictate otherwise and is agreed upon by the company. The soft shut-in procedure is intended to minimise the stresses induced on casing and the formations during the first step of well control. This procedure requires the choke line to be opened first, the bag preventer closed, and then the choke slowly closed. The choke manifold and choke/kill line(s) valve positions during drilling operations shall be as follows: • • •

The remotely controlled power choke on the choke manifold in a half-open position. The outer choke/kill line (hydraulic) valves on the BOP in the closed position, while the inner valves will be open. The choke manifold gate valves upstream of the remote power choke and the valves downstream of the choke to the Mud Gas Separator in the open position.

The driller must hold a record of the tool joint spacing so that a tool joint is at working height above the rig floor and clear of the annular sealing elements, after shut-in. The correct distance at which kelly/top drive is to be pulled above rotary should be posted on rig floor near the BOP control panel. 3.1.

SOFT SHUT IN PROCEDURE (FOR LAND RIGS, JACK UPS AND FIXED PLATFORM)

3.1.1.

Soft Shut-in Procedure While Drilling 1)

2) 3) 4) 5)

6) 7)

Stop drilling. With the pumps on, pick up the kelly or top drive to the predetermined position so the tool joint is clear of the preventer sealing element (and with the lower kelly cock above the rig floor when drilling with a kelly). Shut down the pumps and check for well flow. Open the outer (hydraulic) valve on the choke line at the BOP stack. Close the annular preventer. Close-in the well on the remote power choke at the choke manifold. The remote power choke is for regulating pressure only, and does not isolated pressure, therefore, immediately after the choke is closed, the gate valve upstream of the choke must be closed to ensure that the well is effectively shut in. Space out the string and close the upper pipe rams. Record drill pipe pressure, casing pressure and pit volume readings and calculate the inflow volume. If a float valve is installed, the SIDPP will be derived by pressurising the drill string until communication is established with the annulus.

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Well Shut-In If well pressure plus RPSP exceeds 75% of the rated working pressure of the top drive/standpipe, then use a circulation head and possibly the cement unit. In some cases it may be considered appropriate to open the ram preventer and to keep the string moving through the annular preventer during the control operation to prevent stuck pipe. Moving the string through the preventer may only be carried out if well control is not jeopardised. When killing a well, first priority is to safely execute the well control operation. Potential hole problems have a lower priority at this time and will be dealt with after the well is killed. Use Of A Top Drive When a top drive system is used in combination with stands, it should be possible to disconnect the string at the rotary level to be able to carry out operations which require a tool joint near the rotary table, e.g. installation of circulating head, wireline lubricator, etc. For this purpose a float valve or a drop in sub (preferably a retrievable type drop in valve) should be used to allow disconnection of the string below the lower IBOP of the top drive. 3.1.2.

Soft Shut-in Procedure While Tripping 1)

2) 3) 4) 5) 6)

7) 8) 9)

10)

Stop tripping. Install a full opening safety valve (lower kelly cock) in the open position on the drill string and check for well flow. If this is not possible due to the velocity of the flow, stab on the top drive if in use. Set the tool joint at the correct height above the rotary table . Close the safety valve. Open the outer (hydraulic) valve on choke line at the BOP stack. Close the annular preventer. Close-in the well on the remote power choke at the choke manifold. The remote power choke is for regulating pressure, not for isolating pressure. Therefore, immediately after the choke is closed the gate valve upstream of the choke must be closed to ensure that the well pressure is effectively closed in. Space out and close the upper pipe rams. Connect the kelly or top drive and line up the stand pipe manifold. Record drill pipe pressure, casing pressure and pit volume readings and calculate inflow volume. If a float valve is installed, the SIDPP will be derived by pressurising the drill string until communication is established with the annulus. If the decision is made to strip back to bottom, open the pipe rams and continue as per the ‘Stripping Procedure’ ( Refer to section 4). Otherwise start to bring the well under control as per the ‘Killing Procedures’ ( Refer to section 5).

Well Shut-In If well pressure plus RPSP exceeds 75% of the rated working pressure of the top drive/standpipe, then use a circulation head and possibly the cement unit.

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Use Of A Top Drive During tripping with 31/2” DP in 7” casing, the normally installed 73/8” OD lower IBOP and the 73/4” - 8” OD crossover do not allow stripping operations, due to their large ODs. In this case avoid making-up the top drive at first. 3.2.

SOFT SHUT IN PROCEDURE (Floaters)

3.2.1.

Soft Shut-in Procedure While Drilling 1)

2) 3) 4)

5) 6) 7) 8) 9) 10)

Stop drilling. With the pumps on, pick up the kelly or top drive to the predetermined position so the tool joint is clear of the preventer sealing element (and with the lower kelly cock above the rig floor when drilling with a kelly). When picking up the drill string, the compensator will stroke fully open. Shut off pumps and check for well flow. Open the outer fail-safe valve on the choke line at the BOP stack. Close-in the well on the remote power choke at the choke manifold. The remote power choke is for regulating pressure, not for isolating pressure. Therefore, immediately after the choke is closed the gate valve upstream of the choke must be closed to ensure that the well pressure is effectively closed in. Close the uppermost fixed size pipe rams. It is only acceptable to hang off on variable bore rams, if the tool joint will rest on ram blocks and, not on the fingers. Close the ram locking device, if not automatic. Lower the drill pipe slowly and land tool joint on pipe rams. The lower kelly cock should be accessible taking in account rig heave and tidal conditions. Move the compensator to mid stroke position and adjust to support the string weight above the hang off rams plus a nominal overpull of 15,000-20,000lbs. (7-9t.) Bleed off the well pressure between annular and ram preventers via kill line. Observe the well to verify that the rams are holding. Open the annular preventer. Record drill pipe pressure, casing pressure and pit volume readings and calculate inflow volume. If a float valve is installed, the SIDPP will be derived by pressurising the drill string until communication is established with the annulus.

Use Of A Circulation Head The use of a circulating head is mandatory when the drill string motion compensator is not operational or when circulation pressures are expected to exceed the working pressure of Top Drive/standpipe. Support the drill pipe and circulation head assembly using constant tension winches or a tensioner if necessary. Use Of A Top Drive When a top drive system is used in combination with stands, it should be possible to disconnect the string at rotary level to be able to carry out operation which require tool joint near the rotary table e.g. installation of circulating head, wireline lubricator, etc. For this purpose a float valve or a drop in sub (preferably a retrievable type drop in valve) should be used to allow disconnection of the string below the lower IBOP of the top drive.

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Deepwater Well Control Operation Consideration must be giving to the possibility of the presence of a gas bubble above the BOP at the time of shutting-in. For this reason shut in procedure in deepwater operations should be modified as follows: 1) 2) 3) 4) 5)

3.2.2.

Shut-in the well as per the previous procedure above. Open the diverter lines and close the diverter to prevent gas entering the work area. If the well is flowing at the diverter line close the lower annular preventer. If the well is still flowing, pump fluid to the diverter to prevent riser collapse caused by gas expansion and discharging mud from the riser. If the well is static at the diverter line, open the diverter and continue from step 6 of the previous procedure above.

Soft Shut-in Procedure While Tripping 1)

2) 3) 4) 5)

6) 7)

8)

Stop tripping. Install a full opening safety valve (lower kelly cock) in open position on the drill string and check for well flow, if this is not possible due to flow, stab on top drive if in use. Close the safety valve. Open the outer fail-safe valve on the choke line at the BOP stack. Close the upper annular preventer. Close-in the well on the remote power choke at the choke manifold. The remote power choke is for regulating pressure, not for isolating pressure. Therefore, immediately after the choke is closed the gate valve upstream of the choke must be closed to ensure that the well pressure is effectively closed in. Connect the kelly or top drive and line up the stand pipe manifold. Record drill pipe pressure, casing pressure and pit volume readings and calculate inflow volume. If a float valve is installed, the SIDPP will be derived by pressurising the drill string until communication is established with the annulus. If a decision is made to strip back to bottom continue as per the ‘Stripping Procedure’ ( Refer to section 4), otherwise, hang off the drill string on the pipe rams, adjust the motion compensator and begin to bring the well under control as per the ‘Killing Procedures’ ( Refer to section 5).

Deepwater Well Control Operations Consideration to the possibility of the presence of a gas bubble above the BOP at the time of shutting in. For this reason shut in procedures in deepwater operation should be modified as follows: 1) 2) 3) 4) 5)

Shut-in the well as per the previous procedure above. Open the diverter lines and close the diverter to prevent gas entering the work area. If the well is flowing at the diverter line, close the lower annular preventer. If the well is still flowing provide liquid in the diverter to prevent collapse if gas expands and vacates the riser. If the well is static at the diverter line, open the diverter and continue from step 7 of the previous procedure above.

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3.3.

PAGE

0

POST SHUT-IN OPERATIONS As soon as the well has been shut-in, the Drilling Contractor’s Toolpusher and the Company Wellsite Drilling and Completion Supervisor will take all the necessary steps to ensure the well has been properly secured and to implement subsequent well killing operations. The following inspections will be carried out: • • • • • • • • • • • • • • • • •

Inspect the BOP system components and choke manifold for leaks. Check that all the valves on choke manifold and BOP system are in the correct position (open or closed). Check the BOP accumulator pressure. Stop hot work and shut down any possible sources of ignition. Check for overboard mud leakage and any other pollution. Alert the stand by boat. Confirm the ignition system on flare/burner booms are properly installed and operational. Check that the mud system equipment is working properly (in particular the mud gas separator and degasser system). Confirm breathing apparatus/masks and fire extinguishers are in correct location and in operational condition. Check that anti pollution equipment and dispersant is available on the rig. Check that the emergency generator is working properly. Calculate the inflow volume, the SICP and the SIDPP and fill in the Kill Sheet. Confirm that the mud materials and equipment needed to circulate out the kick are available on the rig. Estimate the volume of extra mud in the pits. Organise the duties of drill crew and Service Contractors for the well killing operation. Establish a communication system that will ensure the information flow among the personnel involved in well killing operations is functional. Organise a plan for possible personnel evacuation.

Prior to starting well killing operations, a meeting shall be held by the Drilling Contractor’s Toolpusher and Company Wellsite Drilling and Completion Supervisor to make all personnel involved acquainted with operating programme and safety procedures. 3.4.

PRESSURE DATA RECORDING Drillpipe pressure and casing pressure must be monitored on the gauges on the choke control panel. Low pressure gauges (which can be completely isolated when required) may be installed on choke line and stand pipe to allow accurate measurement when low pressure kicks are taken but must always be used in deep water operations. These gauges should be calibrated regularly according to the QA schedule, and tested at regular intervals along with the choke and kill line manifolds. At no time throughout the well control operation should the gauges in use be changed.

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4.

STRIPPING PROCEDURE

4.1.

OFF BOTTOM KICKS

0

When a kick is taken with the bit off bottom, the following factors should be considered: • •

Drillpipe pressure is not a reliable indication of actual bottom hole pressure. The position and nature of influx entered into the wellbore cannot be confirmed.

Whenever practicable, and safe the bit should be stripped back to bottom to allow implementation of the most effective and practical killing method. If the well is flowing, under no circumstances will the pipe be run in the hole unless stripping in is implemented. If the well condition or any other circumstances make stripping in impossible or unsafe, then the bullheading, or volumetric method or off-bottom circulation may be considered. 4.1.1.

Preparing To Strip-In Assuming that a decision is made to strip-in, then the well shut-in procedure will have resulted in the installation and closure of a full opening safety valve (Lower Kelly Cock or Top Drive Lower IBOP) on the drill string. Therefore, the following preparatory procedure is suggested: a)

If a float valve is installed: 1) Open the safety valve and check that the float valve is holding. 2) If float valve is holding, remove the safety valve. 3) Proceed with stripping operations.

b)

If a float valve is not installed or is leaking: 1) 2) 3) 4)

If Top Drive is installed disconnect it above the lower BOP by using the pipehandler. Install the inside BOP (Gray valve) on top of the full opening safety valve. Open the safety valve and ensure the Gray valve is holding. Leave the safety valve open and proceed with strip-in.

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The Drilling Contractor, in conjunction with the Company Representative, will prepare a plan for conducting stripping procedures. The following consideration must be taken into account: • • • • • • • • • • • • 4.2.

Organisation and supervision of the drill crew. How to move tool joints through the BOP. Wear on BOP elements and control unit. Internal drill string flow control devices (i.e. utilisation of a retrievable drop-in-dart instead of a Gray valve). Procedure for filling the drill string. Monitoring of pressure and fluid volumes. Wellbore pressures in relation to the Maximum Allowable Pressure for equipment and the formation. Controlling increases in wellbore pressure due to surge pressure. Control of influx migration. Procedures to be adopted in the event that the surface pressure approaches the Maximum Allowable Pressure as the pipe is stripped into the well. Condition of the drillpipe (all drillpipe protectors should be removed). Possibility of stuck pipe.

STRIPPING METHODS Stripping-in through BOP equipment can be accomplished by using one of the following: • • •

The annular preventer. A combination of annular and ram preventers. Two ram preventers.

If the upward force generated by the well pressure acting on the cross-sectional area of the pipe is greater than the weight of the drill string, it will be necessary to force the pipe through the preventer by snubbing. Stripping through the annular is the recommended method. However, the wear on the annular packing element is related to well pressure combined with friction, due to pipe and tool joints passing through rubber, stripping through the bag preventer should be avoided if the pressure exceeds 1,000psi (70kg/cm2). If the surface pressure indicates that annular stripping is not possible, then consideration should be given to reducing the surface pressure, i.e. by off bottom circulating. If conditions require stripping using ram preventers, the lower rams shall not be used but kept in reserve.

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4.2.1.

PAGE

0

Stripping Through Annular Preventers To prevent premature damage to the rubber element while stripping, the closing hydraulic pressure should be reduced to the minimum possible. This minimum is the point at which the bag just begins leaking a slight amount of mud. This mud leak aids lubrication of the drillpipe. The pipe should be lowered through the annular at a speed no greater than 3min per stand and reduced when the tool joints pass through the annular. While stripping a tool joint through the preventer, the pressure regulator should automatically adjusted to the closing pressure, allowing the tool joint through without undue force. If the upper annular preventer fails during stripping operations and further stripping is required, the well must be shut-in using the pipe rams and the annular repaired before continuing with operations.

4.2.2.

Stripping Through Ram Preventers Stripping through ram preventers should only be considered when, the surface pressure is greater than the stripping pressure of the annular preventer or if this pressure cannot be reduced to within safe annular working limits. Bag-to-Ram stripping is preferred to Ram-to-Ram, unless surface pressures are such that the annular cannot operate safely. Whichever method is used the following points must be considered: • • •

Is there sufficient space between the two stripping BOPs to accommodate the tool joints. Is there is a circulation inlet in the stack, between the two stripping BOPs, to allow for pressure equalisation during the double opening-closure operation Never use the lowermost set of pipe rams for stripping.

Taking the above into consideration, Ram-to-Ram stripping is only allowed with a three pipe ram BOP configuration. A two pipe ram BOP configuration can only allow Bag-to-Ram stripping. Limitations for stripping operations should be previously agreed with the contractor and BOP manufacturer. Stripping can be conducted using variable bore rams, but the duration of this should be limited as the stripping capability of VBRs is poor. The well should be secured after stripping operations and the BOP cavities inspected and refurbished.

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4.2.3.

PAGE

0

Annulus pressure control while stripping While stripping in the hole, it is necessary to control the well and prevent a bottom hole pressure increase induced by the drill pipe volume. This is achieved by bleeding off a calculated volume of mud from the annulus. Which should be equal to the volume of pipe and tool joints, steel displacement plus the capacity of drillpipe. Additional mud will be bleed off to compensate for influx migration. Influx migration is indicated by a gradual increase in surface pressure even if the correct volume of mud is being bled from the well. Mud should be bleed from the well at every connection. Mud bled from the annulus must be accurately measured in order to maintain the correct volume balance and bottom hole pressure. Bleeding off should be done through a manually operated adjustable choke into the trip tank as the hydraulically operated choke has an excessive delay in operation. When the drill string is stripped into the influx in the wellbore, the height of the influx column will lengthen rapidly and correspondingly the surface annular pressure will rise quicker. Whether to stop or continue stripping at this point will depend on the pressure, rate of increase in pressure and the distance from bottom. This has to be evaluated on site and correct/remedial actions taken.

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Stripping Worksheet

STRIPPING WORK SHEET Well N° 3

Rig 15

MUD WEIGHT IN THE HOLE 1.75 SG INITIAL BIT DEPTH 2000 m STRIPPING DATA VOLUME OF MUD DISPLACED BY 5 in OVERBALANCE MARGIN: 120 psi VOLUMETRIC CONTROL DATA HYDROSTATIC PRESSURE PER BARREL OF HYDROSTATIC PRESSURE PER BARREL OF HYDROSTATIC PRESSURE PER BARREL OF HYDROSTATIC PRESSURE PER BARREL OF Time hr.min

Operations

Date and Time

10/05/85

Sheet N° 1

LUBRICATING MUD WEIGHT 1.75 SG HOLE DEPTH 2250 m DRILLPIPE: 0.0797 OPERATING MARGIN: 1.75 SG MUD IN 1.75 SG MUD IN 1.75 SG MUD IN MUD IN CHOKE Monitor Pressure (psi)

Change in Monitor Pressure (psi)

550

150

bbl/m psi

:

2.15

5" x 8 1/2" ANNULUS: 16.5 6 1/2 x 8 1/2 ANNULUS: 26 8 1/2" HOLE: 10.8 HOLE: BIT Depth (m)

Pipe Stripped (m)

(bbl)

bbl/stand

(Max) psi/bbl psi/bbl psi/bbl psi/bbl

Hydrostatic of Mud Bled/ lubricated (psi)

Overbalance (psi)

Volume of Mud/ Lubricated (bbl)

Total Volume of Mud (bbl)

0

10:05

Well shut in- pressure stabilised

10:20

Drill pipe dart installed

2000

10:30

Strip in stand N° 1

770

+ 120

2027

27

2.2

N/A

+ 120

0

10:36


890

+ 120

2054

54

4.4

N/A

+ 240

0

0

10:40

Bleed mud at connection

770

- 120

2054

54

4.4

N/A

+ 120

+2.2

2.2

10:45


890

+ 120

2081

81

6.6

N/A

+240

0

2.2

10:48


770

- 120

2081

81

6.6

N/A

+ 120

+ 2.2

4.4

10:53


890

+ 120

2108

108

8.8

N/A

+ 240

0

4.4

10:57


770

- 120

2108

108

8.8

N/A

+ 120

+ 2.2

6.6

11:00

Strip in stand N° 5 (assume BHA has entered influx)

950

+ 180

2135

135

11.0

N/A

+ 240

0

6.6

11:05


8.8

11:10


11:15


11:20 11:25

2000

830

- 120

2135

135

11.0

N/A

+ 120

+ 2.2

1080

+ 250

2162

162

13.2

N/A

+ 240

0

8.8

960

- 120

2162

162

13.2

N/A

+ 120

+ 2.2

11.0


1330

+ 250

2189

189

15.4

N/A

+ 240

0

11.0


1210

- 120

2189

189

15.4

N/A

+ 120

+ 2.2

13.2

11:28


1460

+ 250

2216

216

17.6

N/A

+ 240

0

13.2

11:33


1340

- 120

2216

216

17.6

N/A

+ 120

+ 2.2

15.4

11:40


1590

+ 250

2243

243

19.8

N/A

+ 240

0

15.4

11:45


1470

- 120

2243

243

19.8

N/A

+ 120

+ 2.2

17.6

- vl bled +vl lubricated N/A bled to compensate for pipe

+ vl overbala nce - vl underbal ance

+ vl bled -vl lubricated

+ vl increase - vl decrease

m/ft

m/ft

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5.

KILLING PROCEDURES

5.1.

WELL CONTROL METHODS

0

All methods to be used to bring the well under control are based on the ‘Constant Bottom Hole Pressure’ concept, as recommended by API-RP 59 ‘Recommended Practices for Well Control Operations’. This methods requires a constant bottom hole pressure, slightly higher than the pore pressure, to be maintained at all times throughout the killing operations in order to prevent further influxes occurring. The mud weight necessary to achieve control of the well, shall be calculated as a function of the Shut-In Drill Pipe Pressure, hole depth (TVD) and actual mud weight. Other permitted well control methods, depending on particular situations, are the ‘Wait and Weight’, ‘Driller’s Method’ and the ‘Volumetric Method’. Bullheading may also be considered when the other preferred killing methods are not applicable. Bullheading is often an operationally acceptable permitted method in killing producing wells, e.g. actual production wells or production well tests in cased wells. In an order of preference, the Wait and Weight method is first, but if this is not a practical, then the Driller’s Method will be used followed finally by the Volumetric Method. Once the method for dealing with the kick has been selected by the Company Representative (Wellsite Drilling & Completion Supervisor and/or Drilling Superintendent), the Drilling Contractor’s personnel should perform the operation following the selected method and using the proper practices. The Drilling Contractor's personnel must be familiar with the Kick Control worksheets (Company, Contractor’s approved, or API forms) in use and with the relevant calculations involved. They must be also be able to fully understand and implement the results of these calculations. Eni-Agip’s kill sheets are shown in figure 5.a and figure 5.b. 5.1.1.

Wait And Weight Method The well is shut-in until the mud (kill mud) can be weighted up in the pits to the required density or the reserve heavy mud can be conditioned to the required density. The kill mud is then circulated into the well displacing the kick. Bottom hole pressure shall be kept slightly greater than pore pressure throughout the entire process, while the pump rate is maintained at the predetermined rate.

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Wait And Weight Killing Procedure 1)

2)

3) 4) 5) 6)

7)

8)

9) 10)

11) 12) 13)

Before starting with the killing operation it is necessary to determine the Initial Circulating Pressure (ICP) and the Final Circulating Pressure (FCP) of the kill mud being pumped down hole. A schedule (plot and table) must be prepared in order that the drillpipe pressure can be properly tracked through choke position. The plotted line should be a straight line except when there is tapered strings and deviated wells. It is important that the volume of the kill mud, position of the influx and drill string geometry are known at all times throughout the kill operations. The key control points in this process are: the kill mud reaching the bit; the top of the influx reaching the casing shoe and the influx reaching the choke on surface. The choke will be opened following the pump start up, ensuring that the casing pressure is kept equal (or slightly in excess) of the original SICP. The pump should be brought up to the RPSP speed slowly. Once RPSP is reached, the choke should be adjusted until the standpipe gauge reads the calculated ICP. If the ICP is close to the calculated value, continue with the displacement operation. If it is substantially different, investigate the cause and recalculate the FCP. The pump (drill pipe) pressure shall be adjusted (reduced), using the power choke in accordance with the kill sheet graph and table, accounting for the volume of the heavier kill mud filling the drill string. Pump pressure should not be allowed to drop below the calculated values. Once kill mud reaches the bit, the drill pipe pressure should equal the calculated FCP. From now on, the FCP value shall be kept constant until the influx is completely circulated out. It is important, therefore, that the choke is continuously adjusted to maintain the required drillpipe pressure. This is especially important from the time the influx reaches the choke until neat kill mud is observed. During displacement the pit gain will be recorded so that the position of the influx in the well can be estimated. After circulation is completed (i.e. when kill mud entirely fills the well and circulating system) the pump can be shut down and the well shut-in for pressure monitoring. The casing and drillpipe pressure will both be checked. There should be no pressure on either of the gauges. If, however, there is still some pressure, through-choke circulation will be resumed until the contaminated mud is removed from the annulus. Once the well has been killed, a flow check will be carried out prior to opening the BOP. Drilling crews must be aware that there may be gas trapped under the BOP rams, hence safety procedures should be implemented prior to opening the BOP. Prior to resuming drilling operations a full circulation will be carried out, with the mud being weighed up to a suitable overbalance.

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5.1.2.

PAGE

0

Driller’s Method Two separate circulations are required with this method to kill a well. In the first circulation the influx is circulated out, at a constant pump rate, using the same mud density that is in the hole at the time of the kick. The Initial Drill Pipe Pressure must be held constant, by choke manipulation, to ensure the bottom hole pressure remains constant. After the influx has been circulated out at the end of the first circulation, the Shut-In Drill Pipe and Casing Pressure should be equal, and equal to the initial shut-in drill pipe pressure. The choke pressure during this circulation will be higher than those if the ‘Wait and Weight method’ was used. This leads to greater downhole, stress and pressures. During the second stage circulation, the well is brought under control by circulating the required kill mud into the hole in the same manner as described in the ‘Wait and Weight method’. Driller’s Killing Procedure First stage Circulating out the influx from the well and maintaining constant bottom hole pressure: 1)

2)

3) 4)

5) 6)

Open the choke following pump start up, ensuring that the casing pressure is kept equal (or slightly in excess) of the original SICP. The pump should be brought up to speed slowly. Once the pump has reached the required RPSP speed, record the Initial Circulating Pressure. If the ICP is close to the calculated value, continue circulating, holding constant pump speed and drill pipe pressure. Continue circulating, maintaining the Drillpipe Circulation Pressure and pump stroke constant, until the influx is completely circulated out. The choke will be continuously adjusted to maintain constant drillpipe pressure. This is especially important when the influx reaches the choke, and then when the mud reaches the choke. The pit gain during displacement should be recorded so that position of the influx in the well can be estimated. After the influx has been displaced from the well, the Shut-In Drillpipe Pressure and the Shut-In Casing Pressure should read the same. If the casing pressure is higher than the drillpipe pressure then some of the influx will still be in the annulus, or there will be some differential mud pressure inside and outside the drill string.

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Second Stage Displacing the well with kill mud keeping Bottom Hole Pressure constant. 1) 2) 3)

4)

5)

6)

7) 8) 9)

5.1.3.

Once the kill mud has been prepared, the second phase can begin. It is important that the volume of the kill mud and its position, in relation to the wellbore and drill string geometry, are known at all times during kill operations. Open the choke following the pump start up, ensuring that the casing pressure is kept constant (or slightly in excess) of the value recorded at the end of first circulation. The pump should be brought up to the RPSP speed slowly. Displace the mud in the drill string with the kill mud, keeping both the casing pressure and pump strokes constant, until the kill mud reaches the bit. As the kill mud is displaced down the drillpipe, the stand pipe pressure will tend to decrease accordingly. Once the displacement of the mud in the string is completed, the Final Circulation Pressure (FCP) can be read on the drillpipe gauge. This pressure and the pump speed must be kept constant throughout the displacement of the mud in the annulus, until the kill mud reaches surface. After the circulation is completed i.e. when kill mud entirely fills the well and circulating system, the pump can be shut down, and the well shut-in for pressure monitoring. Both the casing and drillpipe pressures should be checked. There should be no pressure on either gauge. If, however, there is still some pressure, through-choke circulation will be resumed until unbalanced or contaminated mud is removed from the well. Once the well has been killed, a flow check will be carried out prior to opening the BOP. The Drilling crews must be aware that there may be gas trapped under the BOP rams, hence safety procedures should be implemented prior to opening the BOP. Prior to resuming Drilling operations a full circulation will be carried out, with the mud being weighted up to a suitable overbalance.

Volumetric Method The volumetric method can be used to control the gas expansion, migrating up-hole, during the shut-in period. This only occurs when the influx is gas. Situations in which the volumetric method may be applicable include the following: • • • • •

When the mud pumps are inoperable The drill string is far off the bottom, or out of the hole There is a washout in the drill string The bit is plugged The drill string has parted and dropped.

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Volumetric Killing Procedure In this method the bottom hole pressure is maintained relatively constant and slightly in excess of the pore pressure whilst the gas is allowed to expand as it migrates up to the surface. 1)

2) 3) 4) 5) 6) 7) 8)

9) 10)

A constant bottom hole pressure is maintained by bleeding off mud, with an equivalent hydrostatic head, equal to the rise in pressure caused by migrating gas. For instance if the choke pressure rises by 100psi, a volume of mud equivalent to the hydrostatic pressure of 100psi is slowly bled off, maintaining constant casing pressure. Bleed off in very small increments to allow the pressure to respond by using a manual adjustable choke and diverting the mud into the trip tank. Repeat this process until the influx has migrated up to the BOP. When the gas is at the BOP stack, lubricate mud into the well. The lubrication procedure will replace the influx with mud, as the gas is bleed off at the choke. Pump mud into the casing until pump pressure reaches the predetermined limit and stop the pump. Leave the well shut-in for a time to allow gas to migrate through the lubricated mud. Bleed gas from the well until the surface pressure is reduced by the exact amount equal to the hydrostatic pressure of the fluid volume lubricated into the well. Route returns via the mud gas separator and monitor. If a significant quantity of mud is returned, bleeding should be stopped, and further time allowed for the gas to migrate through the lubricated mud. It is unlikely that all the gas will rise to surface as a discrete bubble and it will be mixed through the mud, therefore, will take a considerable length of time to be completed. When using subsea BOP stacks, gas migration may occur in the choke line leading to a reduction in bottom hole pressure. In this case, a dynamic volumetric method is used for venting the gas from the subsea BOP, by circulating down the kill line and up the choke line. Control surface pressure and pit gain with the choke line. Use the kill line be used to monitor bottom hole pressure.

Note:

If the mud weight is insufficient to balance the formation pressure, it will be necessary to strip drill pipe into the well to implement a standard well kill method.

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0

Volumetric control worksheet

VOLUMETRIC CONTROL WORK SHEET Well N° 10

Rig

2

MUD WEIGHT IN THE HOLE 1.85 SG HYDROSTATIC PRESSURE PER BARREL OF HYDROSTATIC PRESSURE PER BARREL OF HYDROSTATIC PRESSURE PER BARREL OF HYDROSTATIC PRESSURE PER BARREL OF OVERBALANCE MARGIN: 200 psi Time

Operations

hr.min

Date and Time

CHOKE Monitor Pressure (psi)

19.00

12/12/96

Sheet N° 1

LUBRICATING MUD WEIGHT 1.85 SG MUD IN 5" x 8 1/2" ANNULUS: MUD IN x ANNULUS: MUD IN HOLE: MUD IN HOLE: OPERATING MARGIN: 150 Change in Monitor Pressure (psi)

Hydrostatic of Mud Bled/ lubricated (psi)

17.5

psi/bbl psi/bbl psi/bbl psi/bbl

psi Overbalance (psi)

Volume of Mud/ Lubricated (bbl)

Total Volume of Mud (bbl)

650

0

0

0

0

100

19.15

INFLUX MIGRATING

850

+ 200

0

+ 200

0

100

19.25

INFLUX MIGRATING

1000

+ 150

0

+ 350

0

100

19.25Ù 01.25

BLEED MUD AT CHOKE

1000

0

- 150

+ 200

+ 8.5

108.5

01.35

INFLUX MIGRATING

1150

+ 150

0

+ 350

0

108.5

01.35Ù03.15

BLEED MUD AT CHOKE

1150

0

- 150

+ 200

+ 8.5

117

03.30

INFLUX MIGRATING

1300

+ 150

0

+ 350

0

117

03.30Ù04.45

BLEED MUD AT CHOKE

1300

0

- 150

+ 200

+ 8.5

125.5

04.55

INFLUX MIGRATING

1450

+ 150

0

+ 350

0

125.5

04.55Ù05.30

BLEED MUD AT CHOKE

1450

0

- 150

+ 200

+ 8.5

134

+ vl overbalance - vl underbalance

+ vl bled -vl lubricated

+ vl increase - vl decrease

- vl bled + vl lubricated

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5.1.5.

PAGE

0

Bullheading The bullheading method should only be considered when normal killing techniques with conventional circulation are not possible or will result in causing critical well conditions. Bullheading is usually only considered when the following situations occur: • • • • •

A H2S influx cannot be handled safely by rig personnel and equipment. A kick is taken with the pipe far off bottom, or even out of the hole. Circulating the kick out may result in excessive gas rates at surface. Kick calculations show that the MAASP will be greatly exceeded during conventional kill operations. Killing completed wells, i.e. actual producing wells or production well tests in cased wells.

Major factors that will be considered to determine the feasibility of bullheading are as follows: • • • •

Characteristics of the open hole formations, including fracture gradients and estimated permeability. Rated pressures of casing, making allowance for wear and deterioration. Size, location and nature of the influx. Consequences of fracturing a section of open hole.

Bullheading should be performed with an aim of not fracturing the formation. The surface squeeze pressure applied should not exceed the precalculated MAASP. Bullheading procedures will be defined and decided at the rigsite, in response to the particular circumstances which prevail, taking into considering that the mud and influx are squeezed back downhole into the weakest exposed open hole formation. If the influx is suspected of containing H2S, it may be acceptable to squeeze it away downhole provided that casing profile and nature of the formation overlaying the weakest strata, ensures proper isolation. In other circumstances, e.g. where surface permeable formations are exposed or only a surface casing is set not ensuring proper strata isolation, this practice is prohibited. 5.2.

HORIZONTAL WELL CONSIDERATIONS The previous described Well Control Procedures should apply at all times, however, the drill crew must take into consideration some particular aspects related to the drilling of horizontal wells: a) b) c) d)

When a long section of reservoir is exposed, there is the potential for large and rapid kicks. Large sizes of influx can exist in the horizontal section with a minimum effect on bottom hole pressure. Assuming that the fluid parameters and pressure are known, the most likely cause of a kick is due to swabbing, losses, or crossing a fault. Where swabbing of fluid in the horizontal section, both the shut in drill pipe pressure and shut in casing pressure will be zero until the influx reaches the vertical section.

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c)

d) e)

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The practice of hole cleaning minimises cutting beds, which can increase the likelihood of swabbing. Always pump out the pipe when tripping in the horizontal section as this will enhance hole cleaning and reduce the possibility of swabbing. Volumetric increases are the most reliable indication of a kick as pit levels and flow rate changes will be the same as in a vertical section. Flow checks while tripping-out do not provide a reliable indication that an influx has not already entered in the horizontal section as migration may not occur in the horizontal section. If a kick occurs, due to a fault or insufficient mud weight, it is unlikely that there is any difference between the Shut In Drillpipe and Shut In Casing Pressure when the influx is in the horizontal section. Until the influx is circulated out of the horizontal section there is no increase in the casing pressure. When killing the well using the 'Wait and Weight' method, the final circulating pressure should be reached when the kill mud reaches at the start of the horizontal section not at the bit. The unevenness of the horizontal sections may also trap pockets of gas on the high side and this may require more than one circulation to be removed.

5.3.

FLOATING RIG CONSIDERATIONS

5.3.1.

Effect Of Choke Line Length When a kick is taken on a floating rig, the influx will be brought to surface via the relatively small diameter choke line. This introduces major problems that are not present when BOPs are at surface, as on fixed rigs. a)

b)

c)

The pressure losses generated in the choke line while circulating are considered and may cause excessive pressures in the wellbore. These pressure losses can be reduced by reducing the circulating rate. If the circulation rate is reduced, it is necessary to have predetermined RPSP for that reduced rate. At least two or more RPSPs should be taken. As an influx enters the choke line, it may cause a critical drop in bottom hole pressure. To avoid this, as a gaseous influx is nearing the seabed, the mud circulation rate should be reduced to the minimum in order to allow, the variations of gas height in the choke line to be monitored following each choke adjustment, and so maintain constant bottom hole pressure. For deep water operations it is necessary to record the pressure losses in the choke, kill and combination of choke and kill lines. During a well control operation, consideration should always be given to opening both the choke and kill lines to the choke manifold. By increasing the flow area, the reaction time will be increased, making it easier to maintain constant bottom hole pressure. In addition, by increasing the choke line volume, the surface pressure will be lower, thus reducing gas velocity, erosional wear and the possibility of a surface system failure.

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5.3.2.

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Influx Removal From BOP And Riser It is possible that gas may have accumulated between the closed BOP and the choke line when used for killing operations. Before opening the subsea BOP, it is necessary to circulate through the choke or kill line in an attempt to remove this trapped gas. Before opening the well, the light mud in the marine riser must also be displaced by kill weight mud. The suggested procedure is: 1) 2) 3) 4)

Isolate the well from the BOP stack by closing the lowermost set of pipe rams, keeping the annular preventer/ram closed. Pump mud through the upper kill line and discharge the tapped gas up the lower kill line. Close the diverter. Open the annular BOP and pump kill mud through the choke and kill line, replacing the light mud in the riser with kill weight mud.

Note:

If the rig is fitted up with a ‘booster line’, the mud in the riser can be changed out by using it before opening the BOP. When the riser is filled with kill mud, redirect the pump feed to the standpipe manifold, open the rams and carry out a further flow check.

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Eni-Agip

Rig name............................................ Well name..........................................

WELL DATA WORK SHEET

Company man.................................... Date....................................................

MEMW

Leack-off test pressure

Kg/cm²

Hydrostatic pressure of Mud to Shoe

+

MAASP

Max. equivalent mud density Kg/ l

Vertical shoe depth

/

Kg/cm²

x 10 =

m

Kg/cm²/10 m

Actual mud density

-

=

Shoe vertical depth

/

Kg/ l

Max. equivalent mud density

Fracture gradient

10 x

Kg/ l

MAASP

=

m

Kg/ cm²

CASING BURST NEW CASING burst resistence

Securety factor

Kg/cm²

x

O.D in.

I.D in.

Allowable burst pressure

R.K.B. - Sea Bed

=

Kg/cm² m

B.H.A.

Capacity l/m

Weight lb/ft

Length m

Volume l

D.P. H.W.D.P D.C. D.C. Tot

Tot 1

Casing O.D. in Capacity l/m

Annulus 1

D.P x CSG.

2

D.P X HOLE

3

H.W.D.P. X HOLE

4

D.C.x HOLE

5

D.C.x HOLE

Length m

l/m

Wt. lb/ft

Volume l

Shoe depht Bit to Shoe volume l

Misured

m 2

Tot

l/m

Vertical

Tot

m 3 l/m

Pumps Type................

S.P.M.

Liner size in............................. Slow Circulate Pressure

Press. loss to choke

Pump Nr 1 Pump Nr 2 Kg/cm² Kg/cm²

Choke Nr 1 Choke Nr 2 Kg/cm² Kg/cm²

Reduced Pump Stroke Pressure

4

Pump Nr 1 Pump Nr 1 Kg/cm² Kg/cm²

l/m 5 l/m

Bit depht Bit diameter

Pump flow rate

l/stk

RPSP

x

eff.

O.D. in.

= I.D. in.

M.D.

m

l/m l/stk

Capacity l/m

Kg/cm²

Length m

Volume l

Choke line Kill line Riser

Figure 5.A - Well Data Work Sheet

T.V.D.

m

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Date.................................................... Well Company

KILL SHEET

Time of

KICK DATA SIDPP

SICP

Kg/cm²

Pit Gain

Kg/cm²

Gom

l

T.V.D

Kg/l

MAASP m

Kg/cm²

KILL MUD WEIGHT SIDPP

Original Mud Weight Kill Mud Weight

Bit vertical depht

Kg/ cm²

:

x

m

10

+

Kg/l

=

Kg/l

PRESSURE RECORDING Time

SIDPP

SICP

SIDPP/TIME SICP//TIME

INITIAL CIRCULATING PRESSURE SIDPP Kg/ cm²

RPSP

+

Kg/ cm²

Safety margin

+

Kg/ cm²

Time

SIDPP

SICP

SIDPP/TIME SICP//TIME P.T.R.Fondo mare

PUMP STROKES

ICP Drill string volume

=

Pump Output

Surface to Bit

Kg/ cm² l

FINAL CIRCULATING PRESSURE

:

l/stk

=

Bit to shoe volume Pump Output

stk

Bit to shoe

Kill mud Weight l

Original mud Weight

RPSP

Safety margin

:

l/stk

=

x

+

Kg/ cm²

=

stk

FCP Total annulus volume Pump Output

Kg/ cm²

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Bit to surface

Kg/ cm² l

:

l/stk

=

stk

DRILL PIPE PRESSURE GRAPH

Pressure

DRILL PIPE PRESSURE CHART Pump STKS Kg/cm² psi

Figure 5.B - Kill Sheet

Pump strokes

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6.

EQUIPMENT REQUIREMENTS

6.1.

BOP STACK SYSTEMS

6.1.1.

Land Rigs, Jack-Ups And Fixed Platform a)

PAGE

0

The pressure rating requirement for BOP equipment is based on the ‘maximum anticipated surface pressure’ as stated in the Drilling Procedures Manual’. Projects that require a different working pressure in the whole system shall be agreed upon by the Company and Drilling Contractor. The minimum BOP stack requirements are as follows: A 5,000psi WP stack should have at least: • •

Two ram type preventers (one shear ram and one pipe ram). One 2,000psi annular type preventer.

A 10,000psi stack should have at least: • •

Three ram type preventers (one shear ram and two pipe ram). One 5,000psi annular type preventer.

A 15,000psi stack should have at least: • •

Four ram type preventers (one shear ram and three pipe ram) One 10,000psi annular type preventer.

b)

While drilling, all pipe ram preventers shall always be equipped with the correct sized rams to match drill pipe being used. If a tapered drill string is being used e.g. 31/2” and 5”, one set of rams will be dressed to match the smaller drill pipe size. During casing jobs or production testing, the choice of pipe rams shall be defined by the Company, depending on external diameter(s) of the casing/drilling/testing string(s) in the operation and BOP stack composition.

c)

At least one ram preventer, below the shear rams, shall be equipped with fixed pipe rams to fit the upper drill pipe in use. The minimum distance between shear rams and hang-off pipe rams shall be 80cm (30”). The use of variable bore rams (VBRs) is acceptable but they should not be used for hanging off pipe which is near to the lower end of their operating range. Rig site repair of BOP equipment is limited to replacing of worn or damaged parts. Under no circumstances is welding or cutting to be performed on any BOP equipment. Replacement parts should only be those supplied or recommended by the equipment manufacturer. Each choke and kill line BOP outlet shall be equipped with two full bore valves, the outer valve of which will be hydraulically operated (preferably fail-safe closed). The minimum diameter of the choke line will be 3" ID, while the kill line should have not less than a 2" ID. Articulated choke lines (Chiksan) are not acceptable unless derogation is agreed for a particular application.

d) e)

f) g)

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A number of various arrangements in the position of the choke and kill line outlets are used in BOP stack configurations throughout the oil industry. The rig operating manual should highlight these variations, their limitations and all the potential uses of a particular layout. The inclusion of shear rams requires the choke and kill lines positions to be such that the direct circulation of the kick, through the drill pipe stub after shear rams activation, can be performed with the drill string hang-off on the closed pipe rams and holding pressure. On a four ram BOP stack, Eni-AGIP recommends that the positioning of choke and kill line outlets below the lowest pipe rams be avoided as these are the like the last resort ‘Master Valve’ of the BOP stack.

Floating Rigs a)

The minimum BOP stack requirements for floating rigs are as follows: A 10,000 psi stack should have at least: • •

Four ram type preventers (one shear ram and three pipe rams) One or preferably two 5,000psi annular type preventers (one annular retrievable on Lower Marine Riser Package).

A 15,000 psi stack should have at least: • • b) c)

d)

e)

f)

g)

Four ram type preventers (one shear ram and three pipe rams) Two 10,000psi annular type preventers (one annular retrievable on the Lower Marine Riser Package).

The upper hydraulic connector shall have a pressure rating equal to or exceeding the working pressure of the bag type preventers. The BOP stack will contain pipe rams that are able to close on every size of drill pipe/tubing that will be run through the stack. The use of VBRs is acceptable but they should not be used for hanging off pipe which is near to the lower end of their operating range. At least one ram preventer below the shear rams shall be equipped with fixed pipe rams to fit the upper drill pipe in use. The minimum distance between shear rams and hangoff pipe rams shall be 80cm (30”). Each choke and kill line BOP outlet shall be equipped with two fail-safe, remotely controlled gate valves, rated to the BOP working pressure. The valves shall be fail-safe in the closed position. The minimum diameter of choke/kill lines will be 3" ID. The function of each line must be interchangeable at surface to be able to line up with both the rig pumps and the choke manifold. A number of various arrangements in the position of choke/kill line outlets are used in BOP stack configurations throughout the oil industry, The rig operating manual should highlight these variations, their limitation and all the potential uses of the particular layout.

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b) c)

BOP CONTROL SYSTEM

6.2.1.

Land Rigs, Jack-Ups And Fixed Platform

b)

c)

d) e)

f)

g)

h) i)

0

The inclusion of shear rams requires choke and kill line positioning such that the direct circulation of the kick, through the drillpipe stub after shear rams activation, can be performed with the drill sting hang-off on closed pipe rams holding pressure. Eni-Agip recommends that choke and kill line outlets are positioned above the lowest pipe rams as these are the like the last resort ‘Master Valve’ of the BOP stack. For deep water operation, it is recommended to use a BOP stack equipped with an injection line to pump methanol or glycol, in order to reduce the likelihood of hydrates forming during well control operations. It is also recommended that pressure and temperature gauges are located on the BOP stack.

6.2.

a)

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The accumulator system should be capable of closing each ram BOP within 30 secs. The closing time should not exceed 30sec for annular preventers smaller than 183/4” nominal bore and 45sec for annular preventers of 183/4” and larger. Hydraulic operating equipment shall have at least a 3,000psi accumulator unit equipped with two regulator valves, one to reduce the operating fluid pressure to 1,500psi and the other for further reduction of pressure for bag type preventer operations. The capacity of the accumulators should be, at least, equal to the volume (V1), necessary to close and open all BOP functions installed on stack once, plus 25% of V1. The liquid reserve remaining on accumulators should still be the minimum operating pressure of 1,200psi (200psi above the precharge pressure). The control panel shall be fitted with visual and acoustic alarms for signalling of low accumulator pressure, as well as control fluid reservoir low level. A minimum of two air-driven pumps and one electrically driven triplex pump is required for charging the accumulators. The combination of air and electric pumps shall be capable of charging the entire accumulator system from the precharge to full charge pressure within 15min or less. In addition to the hydraulic master control panel, the BOP control system shall include at least one graphic remote control panel located on the rig floor near the Driller’s console. Offshore units shall have an additional graphic remote control panel located at a safe distance from the rig floor usually in toolpusher’s office or adjacent to the escape route from drilling unit. Each remote control panel shall be connected to the control manifold in such a way that all functions can be operated independently from each panel. A safety device shall be installed on the BOP control manifold and remote panels to prevent accidental operations of BOP controls such as the closure of the rams (pipe or shear) on the drilling string while drilling or tripping. The BOP end of the control hoses must be flexible and fire proofed. The BOP accumulator electric-driven pump shall be connected to an emergency source of power.

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6.2.2.

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Floating Rigs a) b) c)

d)

e)

f) g)

h)

i)

j)

The accumulator system should be capable of closing each ram BOP within 45sec and each bag type preventer in less than 60sec. Two complete independent control systems (yellow pod and blue pod) are required to ensure redundant control of all stack functions. The rig should be equipped preferably with an emergency and fully independent acoustic control system. This system shall be used when the rig is off location or in the event of a main control system failure. The associated subsea accumulator shall be mounted on the BOP stack, not attached to the LMRP and should have a capacity adequate for closure: one ram type preventer, shear rams, and for releasing the LMRP connector. Hydraulic operating equipment shall have at least a 3,000psi accumulator unit complete with a soluble oil/water reservoir and equipped with two regulator valves, one to reduce the operating fluid pressure to 1,500 psi and the other one for further reduction of pressure for bag type preventer operations. Accumulator capacity should be, at least, equal to the volume necessary to close, open and close (with charging pumps inactive) all ram type preventers and one bag type preventer with a resulting system pressure of 200psi above the precharge pressure. The fluid volume needed to meet this requirement is the theoretical volume to close, open and close the preventers increased by a 25% factor to compensate for fluid lost to function the SPM valves. When a portion of accumulator volume is located on the BOP stack, the additional precharge pressure required to offset the hydrostatic head of the seawater should be considered. The control panel shall be fitted with visual and acoustic alarms for low signalling accumulator pressure, as well as control fluid reservoir low level. A minimum of two air-driven pumps and one electrically driven triplex pump is required for charging the accumulators. The combination of air and electric pumps shall be capable of charging the entire accumulator system from the precharge to full charge pressure in 15min or less. In addition to the hydraulic master control panel, the BOP control system shall include at least two graphic remote control panels. One panel shall be located on the rig floor near the Driller’s console, the other panel shall be located at a safe distance from the rig floor usually in toolpusher’s office or adjacent to the escape route from drilling unit. Each remote control panel shall be connected to the control manifold in such a way that all functions can be operated independently from each panel. A safety device shall be installed on the BOP control manifold and remote panels to prevent accidental operations of BOP controls such as the closure of the rams (pipe or shear) on the drilling string while drilling or tripping. The BOP accumulator electric-driven pump shall be connected on the emergency source of power.

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6.3.

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CHOKE MANIFOLD a)

b) c)

All choke, kill lines and choke manifold components which may be exposed to well pressure shall have a working pressure rating equal to or greater than that of the preventers in use. The minimum recommended size for all choke lines and valves is 3” (76.2mm). All valves shall be of full-opening gate valve types. Choke manifold shall be equipped with at least four flow lines. •

d) e) f)

6.4.

One line shall be capable of bringing the well return directly to the buffer manifold and shall be equipped with two gate valves. • At least three lines shall be equipped with adjustable chokes, two gate valves upstream and an erosion nipple immediately downstream. At least one choke shall be remote hydraulically operated. A graphic scheme of the choke manifold shall be posted on the rig floor. The buffer shall be capable of diverting well returns to the mud gas separator, the shale shaker, the burner booms or the flare line. A choke manifold of different design from that already installed on the drilling unit, may be acceptable but only if approved by the Company Drilling Manager.

INSIDE PIPE SHUT-OFF DEVICES a)

b)

c) d) e) f) g)

The Kelly or Top Drive, shall be equipped with an upper and a lower kelly cock in functioning condition. The kelly cock’s WP shall be equal to or greater than the rating of the preventer stack in use. The upper kelly cock of the top drive shall be hydraulically operated. A spare full opening safety valve (lower kelly cock) that is compatible with drill pipe in use shall be stationed on the rig floor at all times, in the open position and complete with removable handles for ease stabbing. Crossover for connecting the full opening safety valve to the drill collars or tubing in use shall be also stationed on the rig floor. A Gray type inside BOP, with the appropriate connections for the drill string in use, shall be stationed on the rig floor at all times. One drop-in type back pressure valve, complete with seating subs to fit the drill string in use, shall be available. The wireline retrievable is the preferred type. Any type of string tools installed above this sub shall have an ID greater than drop-in valve OD. A set of float valves, one for each size of drill collar, and one for drill pipes in use, shall be kept available.

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MUD GAS SEPARATOR a)

b)

c) d)

6.6.

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6.5.

PAGE

A suitable atmospheric mud gas separator, arranged with the inlet line from choke manifold and the outlet line (discharging released gas) connected to a flare return, must be provided. The mud gas separator design shall be based on the liquid seal system matched to one or more gas outlets (vent lines) leading a safe distance downwind from the well and/or to the top of the derrick. The liquid seal ensures that separated gas vents safely without breaking through to the mud tanks. The mud seal may be obtained by means of an external U-tube or may be based on a dip tube extending into the trip tank. The mud seal should be at least 10ft (3m.) high. Vent line should not be less than 6” nominal pipe diameter. For vent lines exceeding the length of 130ft (40m.), the diameter of the vent line should be not less than 8” to ensure that the back pressure in the vent line does not exceed the hydrostatic mud seal.

DIVERTER EQUIPMENT a) b) c)

d) e)

f)

g)

h) i)

j)

k)

l)

Whenever possible, there must be at least two discharge lines always ending laterally in opposite points of the rig to enable the possibility of blowing to the leeward side. Diverter outlets and lines shall have a minimum internal diameter of 12” for offshore rigs and 10” for land rigs. Welded flanges or clamped connections are mandatory. Diverter lines shall maintain a uniform diameter throughout, and should be as straight as possible to reduce erosion and back pressure (90° or greater bends are to be avoided). Diverter lines should be securely anchored, especially at bends and at the end of the lines. Diverter valves shall be full opening valves, preferably ball valves, and pneumatically or hydraulically actuated. The use of butterfly valves is forbidden. The automated system shall be set, to allow for the immediately automatic opening of the discharge lines, followed by closure of the shale shaker line and before closing the diverter packing. In the panel, bright indicators must show the working pressure of the accumulators and the actual pressure of the various functions. A regulator must permit changes from, the minimum to the maximum closing pressure of the diverter seal. Each diverter system should incorporate a kill line (including a valve) to be able to pump water through the diverter system. Pumping water or mud through this line is important to reduce the risk of explosion or fire during a blow out. This line is also needed to fill up the hole, at all times, so that it can be kept full in the event of losses to the formation. It should be possible to control pumping operations at the pumps as well as on the drill floor. The control system of diverter should be capable of closing any diverter smaller than 20” within 30sec, and any diverter/annular of 20” or larger within 45sec. Diverter valves should be opened before the diverter element is completely closed. The diverter control system should be capable of operating the diverter system from two locations, one to be situated near the drillers position. All control functions must be clearly labelled for identification. When both the diverter system and BOP stack are employed as on floating rigs, control/accumulator systems of diverter and BOP stack shall be separate units and fully independent. The control panel of the diverter assembly must be able to operate the diverter packing,

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m)

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the discharge valves, the shale shaker valve (if installed) both simultaneously and/or separately. The telescopic joint should incorporate double seals to improve sealing capability.

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6.7.

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AUXILIARY EQUIPMENT a)

b)

c) d) e) f)

g) h) i) j) k)

The trip tank system shall include centrifuge pumps, fill up the line, recirculating circuit and a mechanical mud level device equipped with reading indicator easily visible to the Driller. The minimum capacity of the trip tank should be 5m 3 (30bbls). A mud pit level volume indicator shall be installed on each tank of the active mud system. A continuous recording pit level indicator and totaliser, with audible alarm is required to monitor the volume of all active pits. A mud return indicator with an audible alarm shall be installed on the flow line. Each mud pump shall be equipped with stroke counters. The rig shall be equipped with an adequate degasser, to condition gas-cut mud, installed on the mud active system. The 5” OD standpipe manifold lines, connections, valves, and lines from the mud pump to the standpipe manifold shall have 5,000psi minimum WP with welded connections No thread connections are allowed except for 2" size and below. The standpipe manifold shall be equipped with a connection which can be fully isolated to fit a 10,000psi cementing line and fully isolated. Two 5" OD x 19mm wall thick stand-pipes and 31/2" ID x 5,000psi WP rotary hoses, with welded connections are required. The rated working pressure of the cementing lines shall be the same as the BOP which will not be less than 10,000psi. A cementing line should be connected to the kill lines. The burner booms/flare will be connected to the choke manifold. They will be tied in according to the safety regulations in force for the operating zone. An air-operated, skid mounted, high pressure, low-volume testing unit, is required for hydraulic testing of the BOP and manifolds.

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IDENTIFICATION CODE

7.

CASING AND BOP EQUIPMENT TESTS

7.1.

GENERAL PROCEDURES

b)

c)

a)

b) c) d)

7.1.1.

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Contract obligations require that all Drilling Contractor's and Company pressure control equipment must be appropriately and regularly tested according to legislative requirements. Comprehensive test procedures are mandatory and shall be provided by the Drilling Contractor and authorised by Company. Should any of the above tests identify faulty equipment, drilling operations must be suspended and the well secured, if needed, until the faulty equipment is repaired or replaced. Redundancy of the BOP control system, ensures continued operation of the BOP when there is a malfunction in the system or part of the system. However, this does not imply that rig operations continue in the event that there is a failure to the primary or back-up systems. Derogations of this rule are not allowed on exploration wells or when there are failures on essential equipment. If malfunctions occur during development drilling or on marginal equipment, the Company Wellsite Drilling & Completion Supervisor and Drilling Contractor Toolpusher/OIM. unanimously may decide to continue operations, after being properly informed and documented on actual well situation and after having informed the Company operating base Drilling & Completion Manager and the Drilling Contractor Rig Manager. Testing of equipment should be carried out during non-productive time whenever possible and be properly planned to ensure that all necessary equipment is available, properly installed and in efficient operating condition. All pressure tests shall be performed using water. All valves situated downstream of the valve being tested must be in the open position. All pressure tests shall be witnessed by the Company well site Drilling and Completion Supervisor and Drilling Contractor Toolpusher/Subsea Engineer.

Test Recording a)

b)

c)

All BOP tests, drills, function tests, any malfunctions, repair or maintenance to the mud system and well control equipment shall be recorded in the IADC daily reports and shall be signed by both the Drilling Contractor's Toolpusher and Company's Drilling and Completion Supervisor on the well site. They shall also be recorded in the Eni-Agip ‘Daily Drilling Report’. All pressure tests shall be recorded on a pressure recorder chart. Recordings will also include the volumes displaced to reach each test pressure and the volume returned when bleeding back. Test recording charts and documents shall be kept on board and filed by the Contractor Toolpusher. All test records shall be made available upon request by the Company Representative or local authorities.

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7.2.

BOP EQUIPMENT TESTS

7.2.1.

Land, Jack-Ups And Fixed Platforms BOP Pre-Deployment Tests All BOP stacks will be pressure tested at their rated WP, prior to use, on test stumps.

7.2.2.

BOP Tests After Installation After installation on the wellhead the following test procedure will be carried out. 1)

2)

4)

7.2.3.

Pipe rams and annular BOPs shall be tested with open end cup testers to a low pressure of 300psi (21kg/cm2) and to a high pressure at least equal to the maximum anticipated wellhead pressure. Blind/shear rams shall be tested using blind plug testers to the same pressure as stated above for pipe rams. Where a plug tester is not available, blind/shear rams will be tested against the casing each time a new casing string has been set prior to drilling out the cement. In this case the testing pressure will not be succeed 1,500psi (105kg/cm2). In all cases, the maximum test pressure for each BOP test will not exceed 70% of the rated WP of the lowest rated item of equipment in the wellhead assembly, casing or preventer stack assembly, whichever is the lower.

Surface BOP Testing Procedures BOP stack, choke and kill lines shall be flushed with water prior to testing. If a heavy mud, loaded with large amounts of solids is used, particular care in flushing of lines and valves is required. The wear bushing must be removed. A cup tester or a blind test plug may always be used for BOP testing. a)

With a cup tester, the following precautions are necessary: •

• •

b)

An ‘open ended BOP cup tester’ should be used run in on drill pipe inside the first joint of casing. An open end cup tester is required to avoid pressurising of the casing below this point if the cups leak, hence bringing mud flow through the drill pipes to the surface. The drill pipe test string must be able to withstand the total load applied on the cup tester as a function of the maximum testing pressure. To monitor for any casing pack-off leakage, the casing spool outlet valve must be open. The check valve in the casing spool will also be kept open by the appropriate needle valve.

With a test plug, the following precautions are necessary: • •

The surface volume pumped during the test shall be carefully monitored to ensure that the casing is not being pressurised if the test plug seal leaks. To monitor for any casing pack-off leakage, the casing spool outlet valve will be open. The check valve in the casing spool will also be kept open by the appropriate needle valve.

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7.3.

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FLOATING RIGS BOP Surface Test The complete BOP stack assembly shall be tested at the surface on test stumps. All BOP components shall be pressure tested to a low pressure of 300psi (21kg/cm2) and also to their rated working pressure. After the surface tests, all clamp and/or studded connections must be checked for tightness.

7.3.1.

BOP Tests During And After Installation 1) 2) 3)

7.3.2.

While running BOP stacks on the riser joints, the choke/kill and booster lines from surface to the fail-safe shall be pressure tested to their rated WP. After the BOP stack is landed on the wellhead, a full function test on both pods shall be carried out. All BOP components shall be pressure tested with a test plug to a low pressure of 300psi (21kg/cm2) and then to the following pressures: • The lower connector, against one set of pipe rams, to the rated WP of the wellhead or the ram type preventer, whichever is lower. • All the other components, to a minimum pressure equal to, the maximum anticipated wellhead pressure, or 70% of the internal yield pressure of the weakest item of equipment, whichever is the lower.

BOP And Seal Assembly Tests After Setting Casing 1)

2)

3)

The seal assembly shall be pressure tested to a maximum pressure, equal to the maximum anticipated wellhead pressure, or 70% of the internal yield pressure of the weakest item of equipment, whichever is the lower. The test shall be performed at 500psi (35kg/cm2) increments until the test pressure is reached. The surface volume pumped shall be carefully monitored to ensure that the casing annulus is not being pressurised and to avoid collapsing or bursting of the casing. All BOP components, shall be pressure tested to a low pressure of 300psi (21kg/cm2) and to a minimum pressure equal to the maximum anticipated wellhead pressure, or 70% of the internal yield pressure of the weakest item of equipment, whichever is the lower.

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7.3.4.

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Routine BOP Tests While Drilling 1)

All BOP components, with the exception of shear rams, shall be tested to a low pressure of 300psi (21kg/cm2) and to an high pressure at least equal to the maximum anticipated wellhead pressure. In all cases the maximum test pressure for each BOP test will not exceed 70% of the rated working pressure of the lowest rated item of equipment in casing, or BOP preventer stack, whichever is the lower.

2)

Only function the shear rams unless dictated by governmental regulations. Pressure tests of blind/shear rams are not required during this phase.

Routine Subsea BOP Testing Procedures 1) 2) 3)

7.4.

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7.3.3.

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A BOP test will be performed using both pods. If the yellow pod is used for the pressure test, the blue pod will be used for the function test. Fill the BOP test plug running string to the top with water. The string must remain open to atmosphere during the entire test. The volumes displaced to reach the test pressures and the volumes returned when bleeding back shall be recorded. The volume and response time for each function will be compared with the corresponding values recorded during the surface stump test, and any major differences investigated, to detect possible malfunctions.

BOP TESTING FREQUENCY BOP test on the test stump: Every time the rig is moving between wells or any time the BOP stack is pulled for repair during operation on an actual well for floating rigs. BOP tests after installing the BOP stack on the wellhead: After the first installation of the BOP stack on wellhead and any time the BOP is nippled up/down during operations. BOP tests after setting of casing: Any time a new casing string is run and cemented. Routine BOP tests while drilling: Every 14 days, prior to running a DST or production test assembly, or any time requested by the Company or to meet with local regulations.

7.4.1.

BOP Test Durations The BOP 300psi low pressure tests will be performed first. They are to be held for a min period of 5min. If the BOP does not pass the low pressure test, do not carry out the high pressure test. It is recommended that high pressure tests are held for a minimum of 10min. The maximum acceptable pressure drop over this 10min period is 100psi.

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7.4.2.

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BOP Function Tests a)

All preventers and BOP valves, with the exception of the annular preventer and blind/shear rams preventers, should be operated at least once every shift. b) Blind/shear rams shall be operated every round trip in the hole. c) The annular preventer shall be operated when the scheduled routine BOP tests are performed. Pipe rams especially variable bore rams and annular type preventers may be damaged if they are activated without pipe across the stack, otherwise the rubber packing might be extruded and possibly damaged. Therefore these tests shall be conducted by closing rams and annular packing on pipe only. 7.4.3.

BOP Operating Equipment Tests Any time the BOP stack is nippled up and after repairing operations, all BOP operating equipment hoses, control panels, regulator connections, shall be checked and tested to the maximum manufacturer's recommended pressure for closing and opening the BOP's .

7.4.4.

Kill lines, Choke Lines And Choke Manifold Tests Every time tests are carried out on the BOP stack, the associated equipment shall also be tested, with water by the following procedure. Choke/kill lines and valves will be tested during the BOP tests. The choke manifold will subsequently be tested. a) b) c)

7.4.5.

Kill and choke lines will be tested from the choke manifold to the hydraulic operated valve on BOP stack. Each valve of the choke manifold shall be tested individually. After the first BOP installation, the equipment shall be tested at their rated WP. On routine tests, they will be tested at to least the same pressure applied for the BOP test.

IBOP, Cementing Manifold, Pumps And Standpipe Manifold Tests This equipment shall be tested, with water, every time tests are carried out on the BOP stack according to the following procedure. a)

b) c)

Top drive IBOPs or lower and upper kelly cocks, standpipe and all individual standpipe manifold valves, up to the relief valve on the mud pumps shall be tested through a special test sub, made up on the lower kelly cock and installed on the kelly/top drive. Cementing units, cementing manifold and lines. Each valve shall be individually tested. Inside pipe shut-off devices shall be tested through a test sub.

After the first BOP installation, the equipment shall be tested to their rated working pressures. On routine tests they will be tested to at least to the same pressure applied for the BOP test.

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7.5.

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CASING TESTS Casing pressure tests will be carried out according to the pressure stated in the drilling programme. The leading criteria for pressure testing will be the maximum anticipated wellhead pressure. In all cases the test pressure will be no higher than 70% of API minimum internal yield pressure of the weakest casing in the string or to 70% of the BOP WP. When establishing an internal casing pressure test, the differential pressure due to a difference in fluid level and/or fluid density, inside and outside the casing, shall be taken into account. Consideration should be taken on the maximum allowable tensile strength of the casing thread considering the relevant tensile design factor. Each casing shall be pressure tested at the following times: • • •

When cement plug bumps on bottom with a pressure stated in the drilling programme. When testing blind/shear rams of the BOP stack against the casing. After having drilled out a DV collar.

A cemented liner overlap will be positively tested applying a pressure greater than the lea-off pressure of the previous casing. If there is any doubt, an inflow test could be carried out, with a sufficient drawdown to test the liner top to the most severe negative differential pressure that will exist during the life of the well. The test pressure shall be held and remain stable for at least 10-15 mins The test pressure and method for each well are determined on an individual basis and shall be included in the Geological and Drilling Programme. 7.6.

OTHER TESTS WHILE DRILLING The following tests shall be carried out, only if required by drilling programme under the express supervision of Company well site Drilling and Completion Supervisor, which must indicate the methods and maximum allowable pressures to be applied. a)

Formation Leak-Off Test (LOT). Leak-off tests, or formation integrity tests, can be carried out after setting surface or intermediate casing, to determine the maximum mud weight which can be safely utilised below that string of casing ( Refer to the Drilling Procedures Manual).

b)

Casing Integrity Tests. After drilling inside a casing for about 30-40 days, when expressly required by Company Drilling Manager, the casing integrity should be checked, especially in HP/HT wells or in case of deviated holes. Depending on the dog leg severity, this test might be carried out more regularly (refer to the Drilling Procedures Manual).

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8.

BLOW-OUT PREVENTION DRILLS

8.1.

FAMILIARITY DRILLS

0

The purpose of these drills is to familiarise rig personnel with the various equipment and with the techniques that will be employed in the event of a kick. 8.1.1.

Shut-In Drills These drills are correctly to minimise the time required for the Driller and his crew to close in the well properly and quickly, and to confirm that all essential tools and equipment are available in good operating condition. The Drilling Contractor's personnel shall conduct drills to close-in the well, in the shortest possible time, fully comprehending the process. The Company recommends the following procedure : 1) 2)

Without any previous warning an authorised person should activate the alarm signal to simulate a potential kick situation. The Drilling Contractor's crew should follow the established close-in procedure depending on the stage of operations at the current time: • ‘On bottom’: Pick up the kelly or top drive to the correct height, shut down the pumps, then carry out a simulated well shut-in. •

‘Tripping’:

Lower the stand into the hole to the correct height and set the pipe in the slips, stab-in a full opening safety valve (lower kelly cock) in the open position, close the safety valve, the carry out a simulated well shut-in. To train the rig crews, shut-in drills should be planned to also cover the following associated operations: • • • • •

Pull the BHA out of the hole. Running casing. Wire line surveying. Logging (as well for TLC logging, if any). Running tubing (single as well as dual completion running).

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8.1.2.

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Choke Manipulation Drill The purpose of the ‘choke manipulation drill’, is to provide the drill crews with realistic well control training and a feel for the equipment and procedures used for killing a well, by simulating a circulation through the choke manifold under kick condition. The choke manipulation drill should be carried out before drilling out shoe tracks. Drilling Contractor’s crew should: 1) 2) 3) 4) 5)

Run the bit to above the shoe track. Break the circulation and record the RPSP. Close the BOP. Apply pressure to the well, and simulate a circulation under kick condition using the automatic power choke and manual adjustable choke Record the circulating drillpipe pressure and casing pressure.

Consider applying a low pressure to the casing (say 200psi), and bring the pump up to reduced pump strokes controlling the drillpipe pressure according to a predetermined schedule. 8.2.

EMERGENCY ‘ON-THE-RIG’ DRILLS The purpose of these drills is to familiarise rig personnel in reacting to emergency situations that, depending upon their severity ultimately, may lead to the abandonment of the installation.

8.2.1.

Potential Fire On Well And Rig Abandonment Simulation 1)

2)

8.2.2.

Without any previous warning an authorised person should activate the alarm signal, to simulate a fire on well, followed by the rig abandonment. The bit should be inside the casing shoe and not in a troublesome zone. The Drilling Contractor's crew on duty will shut-in the well and hang-off pipe without opening the hydraulic valve on the choke and kill lines, then continue with the necessary steps to simulated rig abandonment by all unnecessary personnel, while the emergency crew should simulate the fire-fighting procedure.

H2S Drill 1)

2)

3)

Without any previous warning an authorised person should activate the alarm signal, to simulate the presence of H2S. The drill against the H2S effects can be operated at two levels: • Alarm drills simulating the presence of H2S in the mud. • Emergency drill simulating the presence of H2S in the air, i.e. in the shale shakers area, on the rig floor, at the mud tanks etc. All personnel must wear breathing apparatus and with the exception of the crews on duty. They must proceed to the windward emergency safe breathing area, while the emergency crew secure the well and simulates the delimitation of the polluted area. H2S drills shall be recorded on the IADC daily drilling report and appropriate company form.

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Abandon Rig 1)

2)

8.3.

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8.2.3.

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Without any previous warning an authorised person should activate the alarm signal, to abandon the rig due to a potential uncontrollable fire on board, uncontrollable blow-out situation or damage to rig structure etc. All Personnel except the crews on duty must get ready to abandon the rig. Operations must suspended for the time the drill is carried out.

WELL CONTROL DRILLS The severity of any well kick can be reduced if it is detected early enough. Crews must be able to recognise the indications of a potential kick and be able to close-in the well properly in the minimum possible time. These drills are intended to test the driller and mud logger on their alertness with regard to an increase in pit volume and to verify that pit level equipment and indicators are operating correctly. The Company Drilling & Completion Supervisor shall plan the drills and evaluate the performance of the rig crew. No advance notice shall be given that a drill is to be conducted, in order to test the degree of vigilance being exercise by the driller and the mud-logger. The time from the moment the drill is initiated, until the crew has reacted shall be recorded, along with the total time needed to complete the drill. All drills and responses shall be recorded on Company Daily Drilling Report and IADC Report. Pit drills shall be recorded on the Company’s appropriate form. To complete the drill, The Drilling Contractor’s crew should also fill in the Kill Sheet. SIDPP and SICP values will be provided by the Company Drilling and Completion Supervisor.

8.3.1.

Pit Drills The purpose of this drill is to ensure that the drill crews are familiar with the Soft Shut-In procedure implemented in the event of taking a kick while drilling. These drills can be conducted in either, cased or open hole. However, if the drill string is in open hole, the well will not be shut-in. 1) 2)

Without any previous warning an Authorised Person, will change the pit level indicator, to show an increase in mud volume. The mud logger is expected to detect the gain and notify the Driller. The Driller is expected to perform the following: a) Detect the pit gain. b) Pick up the kelly or top drive to the correct height. c) Shut down the pumps and check the well is flowing. d) Shut in the well as per the established ‘Soft Shut-In procedures’: open the hydraulic valve on the BOP stack, close the upper bag-type preventer and close the remote choke.

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8.3.2.

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Trip Drills The purpose of this drill is to ensure that the drill crew is familiar with the Soft Shut-In procedure to be implemented as described above. The drill shall be performed with bit inside the casing shoe and not in a troublesome zone. On floating rigs, the drill should include the procedures for hanging of the string on the BOP stack has per normal practice. 1) 2)

8.3.3.

An Authorised Person (without any previous warning), will initiate the drill by manipulating the trip tank indicator or flowline indicator. The mud logger shall detect the gain or incorrect pipe displacement and notify the Driller.

Trip Drill With Drillpipe In The BOP Stack. The Driller is expected to perform the following: 1) 2) 3) 4) 5) 6) 7) 8)

8.3.4.

Detect the pit gain or incorrect pipe displacement. Lower the stand into the hole and set the pipe in the slips. Install a safety valve (lower kelly cock) in the open position. Close the safety valve. Check for well flow. Shut in the well as per the established ‘Soft Shut-In procedure’: open the hydraulic valve on the BOP stack, close the upper bag-type preventer and close the remote choke. Install Gray valve IBOP. Open safety valve and prepare to strip in hole with drillpipe.

Trip Drill With Drill Collar Or Tubing In The BOP Stack. The driller is expected to perform the following: 1) 2) 3) 4) 5) 6) 7) 8) 9)

Detect the pit gain or incorrect pipe displacement. Lower the drill string tool joint or drill collar connection to a working height (it may be necessary to install and run a stand of drillpipe or tubing to allow closure of the BOP). Set the slips, ensure that no stabiliser or other non slick tool is across the preventer. Install the safety valve (lower kelly cock with a crossover) in the open position. Close the safety valve. Latch onto, pick up the pipe, remove the slips and check for well flow. Shut in the well as per the established ‘Soft Shut-In Procedure’, open the hydraulic valve on the BOP stack, close the upper bag-type preventer and close the remote choke. Install a Gray valve IBOP. Open the safety valve and prepare to strip in to hole with drillpipe.

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8.4.

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ACCUMULATOR DRILLS The purpose of this drill is to minimise the cause of equipment failures, to ensure quick initial closure times and to check the ability to continue operations in the event of accumulator pump failure. Accumulator performance shall be proven at the first installation of the BOP on the wellhead. Thereafter, this drill should be conducted after each casing setting before the BOP pressure tests. The following test procedure is recommended : 1) 2) 3)

4)

5) 6)

7)

Position a joint of drill pipe in the stack. Make sure the tool joint is not access the rams. Turn off the accumulator pumps. Record the initial accumulator pressure. This pressure should be the design operating pressure of the accumulator. Adjust the regulator to provide 1,500psi operating pressure to the annular preventer. Close then open the annular preventer, hydraulic valves on choke and kill lines and the pipe ram preventers for the size of pipe being run. Closing times shall be less than 30sec for each ram type preventer. Closing time should not exceed 30sec for annular preventers smaller than 183/4” nominal bore and 45sec for annular preventers of 183/4” and larger. Record the final accumulator pressure. The final accumulator pressure shall not be less than 1,200psi (84kg/cm2). Bleed the accumulator pressure down to 1,000psi (precharge pressure). Turn on the accumulator pumps and record the recharge time. The recharging time from 1,000psi to 3,000psi shall be less than 15min. Reposition all the preventer control valves in the normal operating mode.

Equipment that does not meet these requirements, either, has insufficient capacity or is not in good operating condition and needs repair. At the end of the drill a function test will be conducted to run the accumulator electric pump using the rig emergency generator. 8.5.

DIVERTER DRILLS Because of the limited response time required when diverter systems are employed, the Drilling Contractor shall have written procedures that detail specific emergency action plans. These emergency action procedures should be in operation prior to spudding the well. The purpose of diverter drills is to reduce to the minimum, the time required for a driller and his crew to divert the well flow during a kick. Diverter drills shall not be limited to the rig floor personnel but shall involve all rig personnel. The drills will be prepared in line with the specific procedure that will be adopted in the event of a shallow gas kick. This drill shall be conducted hourly with each crew until the crew is familiar with the drill.

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The Driller is expected to perform the following: 1) 2)

3)

Pick up the kelly or top drive so that lower kelly cock is above the rotary table. Open the diverter lines, close the diverter element and close the shaker valve (auto sequenced operation). Check the closing time (for diverter sizes smaller than 20” the closing time shall be within 30sec, for diverter sizes 20” or larger the closing time should be within 45sec). Circulate through both lines.

8.6.

DRILL FREQUENCY AND RESPONSE TIMES

8.6.1.

Drill Frequency Training Period • •

Shut-in drills. H2S drills.

These tests shall be carried out on an each shift basis, at the beginning of any new activity, any time experienced personnel are replaced with new recruits, especially when key position personnel are involved such as the Toolpusher, Driller and Assistant Driller. Drills shall be repeated until every crew member gains the correct experience and training. •

Choke manipulation drill. This drill should be carried out prior to drilling out surface or intermediate casings string.

Routine Drills • •

These drills shall be executed every week. Potential fire on wellsite and/or abandon rig. Alert or emergency drills have to be performed weekly and repeated before entering the zone where the presence of H2S is suspected, before coring and before making DST or a production test when the presence of H2S is, either, predicted or ascertained.

Well Control Drills: • •

Pit/trip drills shall be carried out on a shift basis every fortnight. These drills shall be conducted also when the well is nearing or entering high-pressure zones. Diverter drills shall be performed prior to drilling out the conductor string.

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8.6.2.

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Timing The time is the most important aspect in shut-in drills and pit drills, and the times required to accomplish the given task shall be recorded. The Reaction times that can be considered as satisfactory to accomplish different drill requirements are detailed below: • •

Shut-in drills. One minute from activation of the alarm signal to being ready to close the bag type preventer. Pit drills. Not more than 2.5min from an observable change in drilling fluid volume to the time the well is closed-in, implementing the soft shut-in procedure.

The correct timing for all other tests will be defined in the Drilling Contractor's Procedures according to the equipment characteristics.

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9.

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SHALLOW GAS Shallow gas is defined as gas that is encountered in a well which cannot be closed in as the well shut in pressure and the hydrostatic head of the fluid in the hole, will probably result in formation breakdown and cause a subsequent surface blow out. A shallow gas pocket is always over-pressured with the magnitude of overpressure at the top of the shallow gas accumulation dependent on the thickness of the gas column. If an anomaly is identified, indicating the possible presence of shallow gas, the primary option is to drill the well from a location away from the anomaly. Where there is a risk of shallow gas, The use of a floating vessel or a jack-up in floating mode which can move efficiently off location, is recommended.

9.1.

SHALLOW GAS INVESTIGATION The well proposals should always include a statement on the probability of encountering shallow gas. This statement should include an assessment drawn from the shallow gas survey (if carried out), the exploration seismic data, historical well data and the geological probability of a shallow cap rock. Even if no gas presence is apparent, it is nonetheless recommended that all measures and procedures necessary to operate in the presence of shallow gas be implemented in all areas where, historically, this event is likely to occur. Primary well control is the only means to protect the well from blowing out, because secondary well control techniques are not normally applicable in top hole drilling operations. Pilot holes may be drilled, up to the conductor string depth, as part of a preliminary shallow gas investigation programme prior to spudding a well where platforms are planned to be installed, in areas with high probability of shallow gas or only a little geological information is available. A rig that can move away safely in case of shallow gas blow out should be used to drill pilot holes (mobile offshore drilling unit or a dedicate soil boring vessel).

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9.2.

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PRIMARY WELL CONTROL Primary well control is the only means to protect wells from blowing out, because secondary well control techniques are not normally applicable in top hole drilling operations.

9.3.

RECOMMENDED DRILLING PRACTICES

9.3.1.

General Practices Shallow gas guidelines for drilling operations are discussed in the following sections. Where possible, floating rigs should be utilised to operate on locations with possible shallow gas because, on balance, the floating drilling unit is safer than a bottom supporter rig when dealing with shallow gas. Recent experience shows that it is also possible to drill a pilot hole with jack-up rig in a floating position to permit a very fast move off from dangerous area in case of shallow gas blow out. The procedures to move a vessel off location in case of a subsea gas blow-out depend on many factors (rig type water depth riserless drilling or drilling with marine riser etc.) It is imperative to specify these procedures for each rig and each well. When drilling riserless and a subsea gas blow-out is experienced, it may be possible to pump kill mud and simultaneously move rig off location a safe distance away from the bubbling gas area. The drill string should be disconnected and released immediately, if it prevents the vessel from moving off location and or when it endangers the rig structure. The drill string disconnecting and releasing procedure should be available and known to all relevant personnel in order that they are carried out efficiently without causing any delays in moving off location. a)

b)

c)

A pilot hole should be drilled in areas with potential shallow gas, as the small hole size will facilitate a dynamic well killing operation. The probability of encountering a kick, the severity of the kick and the chance of dynamically killing the well, determine the pilot hole size to be drilled. Small pilot holes will enhance the dynamic well killing capability, and improve log quality. Generally, it is recommended that a drill 121/4” or smaller pilot hole is drilled. Restrict the penetration rate (recommended ROP = one joint/hr). Particular care should be taken to avoid an excessive build-up of solids in the hole which could cause formation breakdown and hence losses. Drilling with heavier mud returns could also obscure indications of drilling through higher pressured formations and the well may kick while circulating the hole clean. Restricted drilling rates also minimises the penetration into the gas bearing formation which in turn minimises the influx rate. An excessive drilling rate through a formation containing gas reduces the hydrostatic head of the drilling fluid, which may eventually result in a flowing well. All efforts shall be made to minimise the possibility of swabbing. Pumping at the optimum circulating rate, is recommended for all upward pipe movements (e.g. making connections and tripping). In larger hole sizes especially (i.e. larger than 121/4”) it is important to check that the circulation rate is sufficiently high and the pulling speed sufficiently low to ensure that no swabbing will occur. A top drive system will facilitate efficient pumping while tripping out of hole operations. The use of stabilisers will increase the risk of swabbing, hence the minimum required number of stabilisers should be used.

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d)

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a)

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Accurate measurement and control of drilling fluid is important in order to detect gas as early as possible. Properly calibrated and functioning gas detection equipment and a separate flowmeter are essential in top hole drilling. Flow checks must be made before tripping, any time a sharp increases in penetration rate or tank level anomaly is observed. When any anomaly appears on the MWD log (if a MWD data transmission system is used) and at any specific depth referred to in the drilling programme (taken from the shallow seismic survey), it is recommended to flow check at each connection. A float valve must be installed in all bottom hole assemblies which are used in top hole drilling. The float valve is the only down hole mechanical barrier available. Shallow kick-offs should be avoided in areas with probable shallow gas. Top hole drilling operations in these areas should be simple and quick, to minimise possible hole problems. BHAs used for kick-off operations, have flow restrictions which will considerably reduce the maximum possible flow through the drill string. Dynamic well killing operation will then be very unlikely. A stock of kill mud based on hole size, and for off-shore rigs, water depth and riser size shall be prepared before commencement of drilling. The mud weight held in readiness should be slightly less than the fracture gradient from the sea floor to the shoe of the initial casing string. The correct mud weight must be determined for the particular area is being drilling. Before spudding the well, a meeting should be held in order to alert key personnel (Drilling Contractor personnel, mud engineer, mud logging operator included) of the following issues: • • • • • • •

Note:

Risks related to a possible shallow gas blow-out. Considerations on blow-out development times. Requirement for quick action to be implemented by personnel involved in operations. Drilling control (parameters, levels, gas detectors, tripping, etc.) should be strengthened for this phase. For off-shore rigs; emergencies procedures for shallow gas blow-outs (specific procedures for each rig) must be available and also included, for movable rig, procedures for moving off location. For off-shore rig: alert the supply/standby vessels and on-shore base in order to facilitate fast movement off location and, if necessary, the evacuation of personnel. Duties and responsibilities. The above drilling practices may be modified for development wells where it is confirmed that no shallow gas is expected.

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9.3.2.

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Logging Information about the presence and depth of possible hydrocarbons can be obtained from electric wireline logs or MWD, the latter being the preferred method, since early detection obviously enhances the safety of the operation. MWD is the only currently downhole tool capable of shallow gas detection by means of resistivity and gamma ray recording. In the presence of normal gradient formation and gas bearing sands the use of MWD, with almost immediate surface readout, can be valuable in confirming the requirements for specific measures and procedures to be adopted. However, in the presence of over-pressured gas pockets, a downhole tool may be of limited practical value due to the very fast development of a blow out. In development drilling, where there is sufficient geological information available from surrounding wells to determine that there is no shallow gas, logging may not be required, which avoids pilot hole drilling and hole opening operations. However, the use of a diverter system is still recommended if there is a risk of colliding with another well or there is a possibility of penetrating charged sands from leaking or poorly cemented casing strings. Shallow gas detection, with electrical wireline logging or MWD, is not always reliable or conclusive. Excessive hole size and the presence of fresh formation water may mask the shallow gas effect during recording.

9.3.3.

Losses Losses should be avoided during drilling with a diverter system installed. If losses are encountered, they are to be cured quickly using Lost Circulation Material (LCM) or cement. Full returns are to be regained before proceeding to drill ahead. If the losses cannot be cured, possible courses of action include plugging back with cement, either to set casing high or to abandon the hole.

9.3.4.

Cementing Operations The most important item to prevent shallow gas blow-out during cementing job, is an accurate and correct cement programme. In addition, and where applicable, it is recommended that the BOP stack remains nippled up with a small annular pressure maintained during WOC time. There is no available data to determine the effect of gas blocking agents to stop the gas flow.

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9.3.5.

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Drilling Procedures 30” Casing There is no protection against shallow gas in this hole section apart from the dynamic killing option. Running and cementing the 30” casing in a pre-drilled hole, after having drilled a pilot hole, is the recommended technique in areas where shallow gas might be encountered. An important aspect, which always need to be considered, in floating top hole drilling operation utilising a marine riser, is the formation strength at the shoe. If the formation strength at the 30” shoe is considered insufficient the use of the marine riser and diverter system has to be ruled out and riserless drilling should be employed. 20” Casing: There are three main methods used to drill 26” hole in shallow gas area: • • • •

Drill pilot hole and open the hole without riser . Drill pilot hole and open the hole through the riser with underreamer. Drill pilot hole, pull the riser and open the hole. Drill pilot hole through a marine riser with return to seabed via a sub sea exhaust valve (or dump valve) or subsea diverter.

Operation Without The Riser Riserless drilling is considered to be the safest way to cope with the shallow gas problem since the vessel can quickly move away from a subsea blow-out. The risk of riserless drilling increases with decreased water depth. The presence of the water ensures that some hydrostatic pressure is always available to act against the shallow kicking formation. The possibilities of riser collapse and borehole unloading are eliminated. The primary disadvantage involved with drilling in shallow water, without a marine riser, is that a gas kick may result in reduced rig buoyancy due to the presence of a gas bubble in the water beneath the rig. However, case histories show that the effect of buoyancy loss as a result of a sub sea gas blow-out does not represent a major risk to floating vessel. Also because ocean currents are usually sufficiently strong to carry all of the gas safely away from the rig. Water depth has some influence on buoyancy loss, but it has greater influence on vessel instability, especially at very shallow water depth. A minimum water depth cannot be given since many variable factors should be considered for each case.

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Pilot Hole Opened Through The Riser With An Underreamer There are various advantages, unrelated to well control, when using a riser. Using a riser allows treatment of the returning mud stream, considerable saving in time and money, formation samples and gas samples may be examined and evaluated at surface as drilling progresses, the mud gradient can help to control the well. Use of a marine riser while drilling shallow holes does pose some disadvantages; the gas may cause the mud in the riser to unload, this results in decreased hydrostatic pressure acting against the kick which in turn allows the influx rate to increase. Higher pump rates are necessary to outrun kicks having higher rates of fluid influx. Unloading the mud in the riser also allows the hydrostatic pressure exerted by the water outside the riser to act against riser wall, thus raising the possibility of riser collapse. If we attempt to control a shallow kick by a column of heavy mud above the kick zone, the possibility exists that an excess of heavy mud in the riser may cause lost circulation and an even worsen the conditions. The operative time necessary to run and to pull-out the riser. When drilling with a riser consideration must be given to riser release and moving off location if a shallow gas blow-out occurs. 9.4.

DIVERTER SYSTEM OPERATING PROCEDURES The diverter system shall be used for all wells unless there is clear information of the absence of potential shallow gas. Diverting Shallow Gas In An Emergency The conductor pipe diverter system is only intended to divert flow away from the drill floor when there is a kick. It should never be completely closed-in and used as a BOP in an attempt to control the well as they are not designed to hold pressure but only to direct flow overboard. Diverting shallow gas is a well emergency. The blow out contingency plan should be implemented as soon as it becomes apparent that the well cannot be dynamically killed. Specific contingency plans for dealing with emergencies which may occur during diverter operations should be prepared for each rig and each well but should address the following: • • • • •

Shallow gas meeting for all the crew. Diverter drills and exercises. Shut down procedure for ignition sources. Shut-in the well, if this a dynamic killing failure, evacuate all the personnel excluding the emergency team where there is a case of diverter failure evacuate all the personnel. Alert the office base (An office based supervisor should be present on location if diverting shallow gas is a possibility).

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For a movable rig: • • • •

9.4.1.

Disconnecting procedure for the riser; Closing procedures for watertight doors and hatches; Procedures for releasing the drill string from the drill floor; Procedures for moving the rig off location (pulling by anchors or by a towing vessel).

Diverter System There are three main types of diverter: • • • Note:

Surface diverter. Marine diverter. Subsea diverter. which is not common and available only on few rigs. Published studies show that diverter failure rates range from 50% to 70% of all application with the consequence of a very high risk of explosion or/and fire on the rig.

Specific causes of diverter failures are: Erosion

Is primarily dependent on fluid velocity, abrasiveness of the entrained solid and the angle of impact of the solids against system components. Erosion can be mitigated by reducing one or more of these factors. Erosion failures generally have been due to undersized lines and flow path upset that causes turbulence. The minimum required nominal ID of diverter outlets lines is considered to be 12”. Bends, bore size changes and flow path discontinuities produce high particle impact angles and local increases in velocity.

Blockage

Many shallow gas flows contain large quantities of debris (rocks, sand, etc.) and there have been several documented cases in which this debris has packed off at bends in the diverter lines or other obstruction. The pressure surge due to the blockages resulted in failure of other components.

Poor Component Selection

In some cases, valves and other key elements have been installed that could not handle the dynamic condition, pressure surges and debris laden flow. Low pressure, butterfly or guillotine type valves have failed to operate as required or caused line blockages. Gate valves, in general have had problems with trash in the guides. Welded flange or hub connections are mandatory on diverter systems. Quick connections in diverter lines are not allowed. Diverter lines should be straight and properly anchored.

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Slip Joint Packing Leaks

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The slip joint packing element has historically been a source of problems during shallow gas flows on floating drilling operations. The packing elements have then typically failed due to the flowing pressure exceeding the sealing capabilities of the bladder or due to the bladder seizing to the riser and rupturing at the increased inflation pressure.

High Flow Rates In some cases inadequately supported diverter piping has been damaged from vibrations and whipping caused by high flow rate. The insert type diverter cannot divert the flow if the pipe is out of the hole. This type of unit cannot close on open hole and is not be possible to strip back into the well using the bladder sealing element common to the insert type diverter.

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Diverter Test (before start of operations) Before start of drilling operations perform a diverter test as the following: 1) 2)

9.4.3.

Close the diverter on 5” DP (check the closing time, this time depend on the diverter type, usually, smaller then 20” within 30sec, 20” or larger within 45sec). Circulate through both lines.

Diverter Procedure At the first sign of flow, the following actions are required: 1) 2) 3) 4) 5)

Pump the original mud or water immediately at maximum pump rate. Stop drilling. Activate the diverter function (start to evacuate the non essential personnel). If the well is still flowing, pump heavier mud at maximum pump rate. If the well continues to flow after the heavier mud has been pumped, carry on pumping other mud or water at the maximum rate;

Further dynamic kill attempts may be as follows: 1) 2) 3)

Mix heavier mud whilst pumping mud or water at maximum rate. Pump heavy mud at maximum rate. Repeat sequence if dynamic killing is still unsuccessful, but do not use excessive mud weight which could result in formation breakdown.

Note:

Shutting down the pumps to check for flow may result in an even greater influx flow rates. Continuous pumping is recommended especially if there is a suspicion of flow. Historical data shows that once a blow out start with a high flowrate it is very difficult kill the well by dynamic kill techniques. An improved chance of success is for the dynamic kill operation to be initiated as a early as possible at the first suspicion of flow.

Recent investigations indicate that erosion can be reduced in the diverter by injecting water ahead of the diverter as a dry gas condition is the worst case for erosion. Based on this consideration it is always recommended, where possible, to pump water via the kill line especially where it is not possible to pump via another route.

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10.

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H2S DRILLING PROCEDURES The below topics represent Eni Agip general guideline to operate in H2S environment. It is compulsory that the Drilling Contractor has an ‘Emergency Safety Plan’ including a specific procedure for the presence of H2S.

10.1.

EMERGENCY SAFETY PLAN This document will be submitted to Eni-Agip and shall comply with the requirements of the bid. It shall be in accordance with the regulations in force in the Country where operations are to be carried out and shall be an accurate tool aimed at respect to and safety of human life. It will be analysed by Eni-Agip expert engineers. The document shall be constructed specifically for each rig and updated for each well, giving detailed information concerning: Land rigs, Jack-ups and Fixed Platforms • • • • • • • •

Location, type and setting of the alarms. Location of individual protection and first aid equipment. Personnel duties (for each professional position). Meeting points. Composition of the Emergency Team. Evacuation (time and manner of evacuation shall be described clearly). Frequency and manner of drills. Use limits, control and extinguishing of free flame.

Floating Rigs • • •

Riser disconnection. Rig moving using its own propulsion system, anchoring lines and/or supply vessels. Procedures for drill string abandoning in hole.

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DUTIES OF PERSONNEL The Company will ensure that on board H2S briefings provide clear instructions on how the alarm is raised and who is responsible to take action. Anyone on board who believes that they can smell H2S (like rotten eggs) must immediately report this to the senior drill floor personnel or Production Test Supervisor during well testing. Raise the alarm so that the area can be investigated by authorised personnel, suitably equipped with a respirators and using suitable portable detection equipment.

10.2.1. Manager Or OIM a)

b)

The Manager in charge of the operations or the OIM shall arrange the Service Orders and the Emergency Plan bearing in mind the procedures Contained herein. He will agree with the Company on the Emergency Plan which shall comply with this document and distribute it to the supervisor and responsible personnel.

10.2.2. All Personnel a)

b) c) d) e) f)

Shall be familiar with all the instructions and procedures contained in the Appointments and Emergency Plan arranged by the Manager in charge of the operations or the OIM. Shall be familiar with any equipment shown during the safety drills. In emergencies, they must first preserve their own safety. Must aid injured personnel exposed to toxic gas. Must follow their supervisors instructions Must not panic.

10.2.3. Eni-Agip Drilling and Completion Supervisor a) b)

c) d)

e) f)

Shall ensure that any instruction and procedure contained in this document and in the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor are followed. Shall pay attention that all personnel participate in the safety drills when a potentially H2S bearing formation is to be drilled and that the meeting is reported in the IADC daily drilling report. Ensure that drills are performed regularly. Will check the wearing and location of H2S equipment, their compliance with the standards required for the rig (that in a sour area shall not be less than that specified in appendix A). He shall evaluate its functioning, during drills, and shall report in the minutes any suggestion for improvements. Shall evaluate the situation when gas is detected and take corrective action. Will keep in contact with the Eni-Agip District Drilling Superintendent.

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10.2.4. Drilling Contractor's Toolpusher a) b)

c) d) e) f) g)

Will represent the Drilling and Completion Supervisor if he is disabled. Will check that all personnel on board have had a medical examination and ensure that all personnel have received proper safety instructions and are equipped with functioning breathing apparatus. Is responsible for the control and maintenance of the safety equipment. Is responsible for the availability, condition, efficiency, location of, and expiry date of all H2S equipment. Is responsible for the availability and efficiency of the means of communication (radio link, telephone, interphone, walkie-talkie). Is responsible for Contractors' personnel to be familiar with and know how to carry out their own duties in dangerous situations. Is responsible for emergency drills scheduling and performance, and arrange for the proper orders to be given to ensure continuity and functionality of operations.

10.2.5. Driller a) b)

c)

Will replace the Eni-Agip Drilling and Completion Supervisor and Platform Manager or the Toolpusher in their duties if both are disabled. He will ensure that the placing the rig on safety status, if the evacuation of all, personnel should be necessary, in accordance with the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor. Is responsible for the drilling team’s safety and is the Emergency Team’s manager.

10.2.6. Mud Engineer a) b) 10.3.

Will conduct the ‘Gas Garret Train Test ‘ or the ‘Hatch Test’. Will treat the mud with ‘H2S Scavenger’.

OPERATING CONDITIONS AND PROCEDURES There are two different operating alert levels: • •

Condition 1 - Pre Alarm. Condition 2 - Alarm.

10.3.1. Condition 1 - Pre Alarm Condition 1 is when H2S is present in the air - i.e. detected in the shale shakers area, on the rig floor or at the mud tanks in quantities between 10ppm and 20ppm inclusive.

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Typical situations are: • • •

H2S is found in concentrations ranging from 10 to 20ppm. H2S is found in the air, and phenomena such as ‘drilling break’, ‘kick’ or lightening of the mud indicates the ingress of formation fluids into the bore hole. Recovery of a core from a layer which is known to be H2S bearing (see the relevant specific procedure).

Operating procedure 1)

2) 3)

When the presence of H2S is detected, the Mud Logging Unit Operator must immediately inform the Driller, the Eni-Agip Drilling and Completion Supervisor and the Drilling Contractor's Toolpusher. Acoustic and visual alarms must start automatically in the Dog House when the H2S concentration detected by a single sensor exceeds the 10ppm threshold. A similar alarm must also be present in the Mud Logging Unit. Such signals (appropriately loud and visible) must be activated in such away as to be easily seen and heard over the entire location ( Refer to Appendix A).

After having checked the situation, the Eni-Agip Drilling and Completion Supervisor must: • • • • •

Verify the operations on going in the well and consider whether it is necessary to close the BOPs; Give instructions to the Mud Engineer to treat the mud with an ‘H2S Scavenger’; Advise the Drilling Superintendent or the Company's District Representative on duty about the occurrence of a moderately dangerous situation and report every further development; Re-check and test all H2S sensors Take proper actions as per “Safety and Emergency Plan “ prepared by the drilling contractor.

The Drilling Contractor's Toolpusher must: • • • • • •

Instruct a Safety Expert (Assistant Driller) to check the H2S concentration by means of portable detectors. Check the wind speed and direction, in order to define the areas of potential danger. Activate the ventilation system on the rig floor. Take proper actions as per the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor. Notify Eni-Agip Drilling and Completion Supervisor the results of every control and the measurements. All personnel shall act in accordance with the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor.

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10.3.2. Condition 2 - Alarm Condition 2 is when H2S is detected in the atmosphere in quantities exceeding 20ppm in the shale shakers area, on the rig floor or at the mud tanks Typical situation are: • •

H2S is present in the atmosphere in concentrations greater than 20ppm. Although the sour gas concentration of 30ppm is not dangerous to human life, it indicates a ‘Level of Concern’.

Operating Procedure 1)

2) 3) 4)

When an H2S concentration greater than 20ppm is detected, the Mud Logging Unit Operator must immediately inform the Driller, the Eni-Agip Drilling and Completion Supervisor and the Drilling Contractor's Toolpusher. An acoustic and visual alarm must automatically turn on in the Dog House. Similar alarms must also be present also in the Mud Logging Unit. These signals must be visible and audible from the whole location (see Appendix 2). For offshore installations, air aspirators for ventilation living quarters, engine room and all closed rooms shall be closed-in and all personnel shall act in accordance with the ‘Safety and Emergency Plan’.

The Eni-Agip Drilling and Completion Supervisor must: 1) 2) 3) 4)

Give instructions to restore normal operating conditions (employing ‘key personnel’). Advise the Drilling Superintendent or the Company's District Representative on duty about the existence of a the dangerous situation and report every further development. Submit to all H2S sensors further tests by means of portable detectors Take proper actions as per “Safety and Emergency Plan “ prepared by the drilling contractor.

The Drilling Contractor's Toolpusher must: • • • • •

Instruct a Safety Expert (Assistant Driller) to check the H2S concentration by means of a portable detector and determine the quickest and safest escape way. Check wind speed and direction in order to define the areas of potential danger. Turn on the rig floor fans when they are foreseen. Instruct to light the flare ‘pilots’. Inform the Eni-Agip Drilling and completion Supervisor about the results of every inspection and measurement.

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The Driller must: 1) 2) 3) 4) 5) 6)

While the pumps are working, lift the kelly or the top drive till the lower kelly-cock is above the rotary table. Stop the mud pumps. Open up the choke line hydraulic valve. Let the drilling string lean on slips. Close BOP. Close the adjustable choke on the choke manifold.

All Personnel Not Engaged On The Rig Floor, must •

On onshore rig wear the breathing apparatus (i.e. 10min) Automatic Positive Pressure Escape Breathing Apparatus); go to the emergency safety area, windward (previously assigned by Drilling Contractor's Toolpusher) and wait for further instructions. • On offshore rig take proper actions as per “Safety and Emergency Plan “ prepared by the drilling contractor 10.3.3. Core Recovery In Presence Of H2s After coring in a H2S bearing formation, it is necessary to wear the Cascade System masks (if available ), or Self Breathing Apparatus with 30-45min bottles, during the whole core recovery operation, both using a rubber type core barrel or a inner tube core barrel. A specific section of the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor shall be dedicated to coring operations. 10.3.4. Well testing in presence of H2S The risk of encountering H2S must be assessed from available information relating to the current well and other wells in the area. Danger signals must remain displayed while also carrying out production testing where a presence of SO2 greater than 5ppm is expected (due to the combustion of layer fluids). H2S Emergency Provisions In the event that the occurrence of H2S is a possibility, provisions must be made as follows: 1) 2)

3)

Detection - any H2S fixed or portable detectors which may be required in addition to those already on board. Wind Direction - indicators such as pennants or socks will be positioned in at least 4 locations such that the movement of H2S can be foreseen and its impact on escape routes/ systems and support vessels/helicopters can be assessed. Any person working on a rig that is drilling in a known H2S area or which encounters H2S while drilling must be clean shaven.

The Production Superintendent and representatives from the Drilling and Safety Departments must inspect the rig and ensure that a safety meeting has been held before the well test operations start. General Procedures The requirements below must be reconciled with the Drilling Contractor’s onboard equipment

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and emergency procedures to ensure that they cover all the points addressed. In the event that there are deficiencies they must be dealt with to ensure that the overall provisions are at least equivalent to the requirements of this manual. Detection Detection is accomplished by smell, mud analysis, fixed detectors and hand held detectors. Only the fixed detectors will automatically provide an alarm, all other detection methods require personnel to raise the alarm. Brine/Mud Analysis In the event that brine/mud analysis shows the presence of H2S, the logging engineer will immediately raise the alarm indicating the level of gas. He must be provided with adequate means of communication. Personal Monitor Any detection of H2S by personal monitor must be reported immediately to the senior drill floor personnel or Production Test Supervisor during well test operations and the OIM, giving the location of detection and the concentration measured. Fixed Detectors Provision of the fixed detectors must be such that detection of H2S will result in a suitable alarm being raised in all areas manned during drilling or well test operation, i.e. in the mud treatment room and in the control room, and also give the detector position and the concentration detected. Safe Breathing Areas (offshore rigs) The OIM will designate at least two Safe Breathing Areas (SBAs) of which one will be in the open air upwind of any incident. The second SBA will be inside the accommodation in the gallery/cinema/recreation area. An H2S detector will be provided in the inside SBA and must be switched on when the alarm is given. If deemed necessary, a second open air SBA will be designated to ensure that at least one SBA will be upwind of any incident. H2S Detection While Tripping Prior to pulling out of the hole, circulate the brine/mud system. Circulating All drill floor and mud room personnel will wear SCBA and be masked up (fireman’s sets or tied into the cascade system) immediately. At the same time the mud/gas separator (degasser) will be started and all non essential personnel will be warned to stay away from the drill floor and mud treatment areas. Mud logging personnel will inform the Toolpusher and the OIM when the trip gas is up and when the H2S level falls below 10ppm. Logging When pulling out of the hole, all tools and cable must be washed with scavenger and spray inhibitor. Persons handling repeat formation tester (RFT) samples/chambers must wear SCBA until the chamber has been vented and purged.

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Flow Testing During this phase (time from first opening of test tools until tools are recovered to surface) H2S will be produced to the surface for the first time with consequent increase in risk. To counter this the following precautions are required: 1) 2)

Before well test operations take place: The onshore Drilling Manager/Drilling Superintendent, Snr Production Engineer, Workover Superintendent and Safety Superintendent in consultation with the Rig OIM, the offshore EniAgip Senior Drilling Supervisor and Production Test Supervisor must agree whether or not it is necessary to specify any in stream concentration of H2S at which the well test crew and other essential personnel involved in well test operations must mask up.

3)

A safety meeting prior to opening the well must be held to inform all personnel of the increased risk of the presence of H2S. All testing equipment and systems must be capable of withstanding the effects of H2S. All critical activities such as the first opening of downhole tools must be performed in daylight. All personnel considered by the OIM to be non-essential must be taken off the rig before the start of the test and remain off until after the end of the test.

4) 5) 6)

7) 8)

9) 10)

11)

12) 13)

14) 15)

During the testing period, all off duty personnel shall be restricted to the accommodation area and their movements will be controlled by the OIM. At the production of first hydrocarbons to surface, essential personnel will all wear SCBA and be masked up. Masks will be worn until the level of H2S being produced has been established at the choke or at the separator. In stream H2S levels will initially be monitored every 10min for changes, initially, and thereafter at periods agreed by the OIM, Production Test Supervisor and H2S technician. When H2S is present in the flowstream, the well will be shut-in if the wind speed is less than 5 knots. In any event, it is the responsibility of the OIM to decide if the wind speed or direction presents a hazard which requires the suspension of testing. Testing personnel must wear SCBA and mask up prior to operating or performing work on equipment or systems which have contained H2S, e.g. changing chokes, operating flowhead valves, using bubble hoses, taking separator samples, etc. No open tanks will be used for collecting flow products. Surge tanks and separators will be equipped with vent/overflow lines which discharge at the flare. Background levels of H2S will occur from various sources such as flare residue, valves, flanges, couplings etc. This level must be monitored for increases so that preventative actions can be taken. The installation must be monitored for the presence of sulphur dioxide (SO2) using portable monitors. When the test tool retrieval gets to within five stands of tubing from the first test tool, i.e. the reverse circulating valve, all rig floor personnel will wear SCBA and be masked up until the testing string has been broken down, sample chambers have been emptied and purged and slip joints stroked.

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EMERGENCY CONDITION An ‘Emergency Condition’ is termed any situation where, according to the Eni-Agip Drilling and Completion Supervisor and Drilling Contractor's Toolpusher, there is a significant and uncontrollable air pollution from H2S and/or where it is impossible to keep well operations under control using the equipment available on the rig site. Some of the typical situations are : • • • •

BOP malfunctioning while controlling a kick. Blow-out ‘behind’ the surface casing. Blow-out inside the drilling string (with rams closed). The sour gas concentration reaches a value of LC 50 (Lethal concentration). LC 50 has been defined to correspond to an H2S concentration of 444ppm under a prolonged inhalation of 4hr. Similar for SO2, the LC 50 represents a concentration of 2,520ppm under an inhalation of 1hr (The data are taken from the ‘Dangerous Properties of Industrial Materials’, published by Van Nostrand Reinhold, New York).

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10.4.1. Emergency Operating procedure When the alarm hotter rings constantly: 1)

On onshore rigs, all personnel not engaged on the rig floor must wear the breathing apparatus (10 min. Automatic Positive pressure Escape Breathing Apparatus), proceed to the emergency safe area windward and wait for further instructions. After setting the whole rig to the safety condition, the motorman must stop all engines and start the emergency generator to serve lights, accumulator and radio bridge. 2) On offshore rigs, the Eni-Agip Drilling and Completion Supervisor alert supply vessels available in the area, to approach the rig on the windward and initiate proper actions as per the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor; After having ascertained the emergency situation, the Eni-Agip Drilling and Completion Supervisor must: 1)

Advise the Drilling Superintendent and the Company District Executive on duty, or the District Telephone Operator, about the existence of an emergency condition. 2) Report to the Drilling Superintendent or to the District Representative on duty (either directly or through the appointed person) about the actual situation, the actions taken and the future measures to be agreed upon. The information is to be transmitted through the enclosed forms (Appendix A). It will allow to state whether the hazard area can be delimited or not on onshore rigs. The Drilling Contractor's Toolpusher Or OIM. must: 1) 2)

On onshore rigs, arrange the vehicles for the evacuation of personnel windward; On onshore rigs, ascertain that all personnel have left their working place and moved away, staying windward, at least past the distances indicated in the table 10..

Gas Output (1,000 Nm3/day)

Concentration H2S (%)

Radius of danger area (m)

3,000

10

1,200

1,000

10

600

3,000

1

300

1,000

1

160

3,000

0.1

80

1,000

0.1

40

Table 10.a - Radius of Danger Note: 4) 5) 6) 7)

The danger area radius is calculated in calm wind conditions ( < 1 m/sec).

By means of a walkie-talkie, make sure that the evacuation is completed. Organise monitoring of the area as indicated by the table 10. above on onshore rigs. On offshore rigs, act in accordance with the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor. The Emergency Team shall act in accordance with ‘Safety and Emergency Plan’ prepared by the Drilling Contractor and secure the well (as per the ‘Well Control Policy’ issued by Eni-Agip). The Emergency Team shall remove or deactivate any explosive mixture or agent present on site.

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The Drilling Superintendent or the Company's District Representative on duty, as soon as he is informed about the events and has agreed with the Eni-Agip Drillingand Completion Supervisor at the field on the immediate actions to be taken, must: 1) 2)

Inform the Drilling and Completion Manager of the district. Proceed to the location and join the Emergency Team as Manager of operations, until he will be relieved by the Emergency Manager from the San Donato Milanese Head office.

As soon as he is informed, the Drilling and Completion Manager of the district must: 1) 2)

10.5.

Give out instructions according to the ‘Eni-Agip Emergency Plan’. Advise the District Manager as well as the Eni-Agip Head Office in San Donato Milanese and, if necessary, request co-operation from Districts or Head Office.

ACTIONS TO TAKE FOR THE CONTROL OF AN EMERGENCY Since different occurrences require to be approached differently, it is not possible to detail any given situation. Below we make a list of the actions, responsibility and duties of the Emergency Team.

10.6.

EMERGENCY TEAM Eni-Agip Drilling and Completion Supervisor and Contractor Toolpusher or OIM, after fulfilling the duties previously said, shall subdivide the Emergency Team in groups that shall follow up the well behaviour and evaluate the gas rate, actions to be taken utilising the rig equipment, measure the H2S concentration with portable apparatus, etc. They will follow the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor and will be equipped with: • • • • •

Portable sensors (1 for each group). Calourimetric phials for H2S. Calourimetric phials for SO2. Walkie-talkie (with earphones and laringophones). Bottles for self contained breathing apparatus.

They will keep contact with Eni-Agip Drilling and Completion Supervisor and Contractor Toolpusher or OIM continuously, reporting any developments of the situation.

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DELIMITATION OF THE POLLUTED AREA (ONSHORE) • • •

It is the specific duty of the emergency team (in on-shore installation) to determine the borders of the polluted area. The changes in weather or well situation may entail a change in the radius and extent of the danger area. For the above reason it is hugely important to mark the borders of the polluted area which must be systematically updated.

The situations where the area markings are lost or its limits trespass the location perimeter are particularly serious. In this case the Eni-Agip Drilling and Completion Supervisor (who will be constant radio contact with emergency team and the District office) will inform the Emergency expert/Drilling and Completion manager and wait for instructions. 10.8.

PERSONNEL TRAINING All personnel, engaged in the field, must have knowledge of the procedures set forth herein and participate in the relevant drills. This rule refers to Eni-Agip personnel as well as to the Drilling Contractor's and any Service Company's personnel. Training drills shall be performed regularly while drilling is ‘safe’, i.e. before entering a formation which is potentially H2S bearing. Note:

To be successful, the emergency operation requires the presence on the rig of personnel highly qualified to work in hazardous conditions and whom have to attended the subject training course before field training.

10.8.1. Safety Meeting During a ‘Safety Meeting’ which will take place before stating the potentially dangerous operations are started, the training of personnel by the personnel mentioned in the ‘Safety And Emergency Plan’ prepared by the Drilling Contractor will be achieved by dealing with the following topics: a) b) c)

The dangers of hydrogen sulphide to be explained in detail. Field logistical distribution, location of breathing apparatus, use of wind socks , movement of personnel towards the safe emergency area. Use of: • • • • • • •

Breathing apparatus H2S portable detectors SO2 portable detectors Combustible gas detectors Revival equipment Portable extinguishers Alarm system.

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Personal practice in assistance of people and surveillance (to prevent accidents and to give aid promptly). Introductions to personnel if there is unexpected H2S rush: • • • • •

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Do not to panic Do not to breathe (Before donning a breathing apparatus) Wear protection breathing equipment (10 min. Automatic Positive Pressure Escape) and abandon the polluted area. Move to the indicated emergency safe area and wait for instructions. Those who have a breathing apparatus (30-45 min. Self Contained Breathing Apparatus), must wear it, and return to the polluted area to rescue anyone in difficulty.

H2S PREVENTION DRILLS Prevention drills are to be recorded on the IADC daily drilling report and in the H2S Drill form ( Refer to Appendix A), enclosing a copy of the minutes of the meeting with name and signature of all participants, as well as any remarks). H2S prevention drills have two levels: • •

Alarm Drills Emergency Drills

10.9.1. Alarm Drills When the acoustic alarm are sounded (simulating the presence of H2S), all personnel shall behave in accordance with the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor. To illustrate this, typical a drill scheme is given below : a) b) c) d) e) f)

All personnel (‘key personnel' excepted) must proceed to the windward emergency safe area. The Derrickman must light the flare pilots and proceed to the mud pit area. The Toolpusher and the Driller are to check that the portable detectors are fully operational. The Toolpusher must check wind velocity and direction. The Assistant Driller and the electrician must measure the H2S concentration in the leeward area, using the portable detectors. After e) above that, three Floormen, wearing breathing apparatuses(30-45 min. Self Contained), shall return to the rig floor together with Driller, Assistant Driller and Derrickman, and pull out two drill pipe stands. The Derrickman must climb to the derrick deck, together with another person, both wearing an breathing apparatus.

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10.9.2. Emergency Drills When the continuous alarm siren, signalling an emergency is sounded: a)

b) c) d)

All personnel shall immediately wear the breathing apparatus (10min Automatic Positive Pressure Escape) and, except the personnel engaged on the rig floor, proceed toward the life boats or in the safe windward area; The Driller shall stop any operation at the rig site, leaving the drill string on the slips with the kelly installed; The Motorman shall stop up engines and start the emergency generator; The OIM or the Toolpusher shall check that H2S and explosive mixture portable meters are fully functional.

10.9.3. Drill Frequency Alert and Emergency Drills shall be carried out in accordance with the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor. However, in areas where H2S presence is expected or confirmed, they have to be carried out weekly. They also have to be performed whenever pulling up into the shoe and repeated before entering any expected H2S bearing levels e.g., before to perform coring, DST or production testing. Results shall be reported on the IADC daily drilling report and on the dedicated form (Refer to appendix A). It is important to measure the time required for personnel gathering and being accounted at the meeting point. 10.10.

H2S DETECTION SYSTEM The drilling platform or rig will be equipped with a fixed H2S monitoring system, capable of recognising the presence and concentration of the previous stated levels of.

10.10.1. H2S detection in air A box for the detection of H2S in air must be installed in the ‘Dog House’. The system will consist of a unit capable of measuring gas concentrations in air at four varies sites (shale shakers, rig floor, bell nipple and mud pit) and activate the sound alarm and lights when the danger threshold is reached. For off shore drilling units the sensors shall be positioned, as the very minimum, at the following locations: • • • • • • •

All air inlets to closed rooms Shale-shaker area Pumps room Rig floor Below the rotary table Mud pits Cellar deck/moonpool.

During production testing additional sensors must be placed near the separators, heater, etc.

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10.10.2. Sensor Ranges The system measuring capacity must be 0-50ppm in air. Danger thresholds are set as follows: • •

Pre Alarm: for a concentration between 10ppm and 20ppm in air; Alarm: for a concentration upper of 20ppm. in air

The alarms set up by the ‘Dog House’ and the ‘Mud Logging Unit’ must operate automatically, but also allow manual operation. Three portable detectors must be available on the rig and provided with colourimetric vials for the detection of H2S and SO2. These detectors must be used in areas not monitored by the fixed system and if the gas concentration exceeds measuring limits of the fixed sensors.

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10.11.

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BREATHING APPARATUS AVAILABILITY

10.11.1. Standard Equipment For All Rigs The standard land rig must include the following individual protection means: •

Breathing apparatus (10 mins Automatic Positive Pressure Escape Breathing Apparatus).

Apparatus of the overpressure type with supply of 45 spare cylinders, capable of providing an autonomy of nearly two hours to emergency team personnel. They must be distributed within the rig as indicated by the following appendix A 30 - 45 Minute Self Contained Breathing Apparatus Drilling Team 5 Motorman 1 Mud Engineer 1 Mud Logging Unit 1 Eni-Agip Supervisor 1 Toolpusher 1 Tourpusher 1 Extra Supply 4 TOTAL 15

10 Minutes Automatic Positive Pressure Escape Breathing Apparatus Drilling Team 5 Motorman 1 Mud Engineer 1 Mud Logging Unit 2 Eni-Agip Supervisor 1 Toolpusher 1 Tourpusher 1 Assistant Motormen 1 Electrician 1 Eni-Agip Geologist 1 Store Yard team 3 Gusts 3 Extra Supply 9 TOTAL 30

Table 10.A - Breathing Apparatus Distribution The minimum standard for equipment on all drilling platforms shall include the following individual protective breathing apparatus: • •

Protecting Breathing Apparatus (10min Automatic Positive Pressure Escape) the quantity equal 120% of the number of people that can be accommodated on board. Self Breathing Apparatus of a quantity equal to 120% of the total number of personnel in the emergency team and provided with minimum of 3 spare bottles each.

According to the list of standard equipment (Refer to Appendix A), supply vessels and boats assisting the drilling unit operating in H2S area, shall be equipped with the following individual means of protection: •

Breathing Apparatus of a quantity equal to 120% of the number of crew and provided with a minimum of 3 spare bottles each.

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10.12.

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CASCADE SYSTEM Where the H2S risk is high and protection means are used frequently, the use of apparatuses with 30min air reserves would be impractical and require rig personnel to maintain a careful and precise check of the air available in the cylinders. To overcome such problems drilling rigs or platforms must be equipped with a fixed system or Cascade System for the supply of the necessary air, in addition to the standard equipment. Rig personnel shall connect themselves to the system at point appropriately arranged, using the umbilical hose provided with a rewinding automatic device (some of which may be as long as 20m). Connections for umbilical hose and pressure regulators are to be distributed as a minimum at. Land Rig Rig floor Derrick deck Near the substructure Shale shakers Mud pit Mud pumps and engines

2 manifolds, each provided with 5 connections 1 manifold provided with 3 connections 2 manifolds, each provided with 5 connections 1 manifold provided with 5 connections 1 manifold provided with 5 connections 1 manifold provided with 5 connections

Platform Rig floor Cellar deck/moonpool Monkey board Crane box/cage Shale-shaker area Mud pit room Pumps room Engine room SCR box Control room • • •

2 manifolds with 5 connections each 1 manifold with 5 connections 1 manifold with 3 connections 1 manifold with 3 connections 1 manifold with 5 connections 1 manifold with 5 connections 1 manifold with 5 connections 1 manifold with 5 connections 1 manifold with 3 connections 1 manifold with 3 connections

The cascade system shall be equipped with bottles arranged in ranks and positioned as per the ‘Safety and Emergency Plan’ prepared by the Drilling Contractor. The minimum air reserve available (number of bottles) shall be at least enough to allow 10 people to work for 10hrs in normal breathing conditions without recharging bottles. For these it is preferred to have systems, the installation of two compressors located so as to allow to access to either one of them for bottle recharging to cater for the direction the wind blows.

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The Compressors shall have the following features: • • • • • • •

Note:

Capacity equal to 17cu ft/min (480 l/min) Maximum charge pressure 3,000psi (208bars) Filters and air cleaners as per DIN 3188 regulation Alarm and control system for CO2 high temperature and oil content Gauges, safety and oil pressure control valves Double powering: electrical and diesel Skid and protection structure.

Installation and testing of the cascade system cannot be carried out by drilling contractor personnel, but only by specialists.

Where previous operations in the area have already ascertained the presence of H2S, it is recommended to stipulate contracts with contractors for, the supply of equipment, training of field personnel, inspection of equipment efficiency, and an expert assigned to the rig. 10.13.

USE OF BREATHING APPARATUS The 10min Automatic Positive Pressure Escape Breathing Apparatus must be used only to abandon the danger area. Such apparatus (which each worker must always have at hand ) located by the rig floor, substructure, mud pumps, shale shakers, mud mixing area, engines and mud logging unit must be worn when the alarm activates. The 30-45min Self Contained Breathing Apparatus must be worn when working in a polluted environment or when having to enter a polluted closed area. In the latter case their must always be two operators in a team.

10.14.

ADDITIONAL SAFETY FEATURES A drilling rig operating in a ‘sour area’ must be provided with the equipment related in the Appendix A. With reference to items not previously addressed, the following considerations must be made: • • • •

For land rigs, access to the rig is to be provided with a gate or barrier forbidding admittance to personnel not concerned with operations. Two wind sleeves or flags, at minimum, must be set up in such a way as to indicate wind direction. They must be visible from the rig and from the emergency safe area( visible day and night), by placing close to lights. The rig must be provided with two or more fans to ventilate rig floor, substructure shale shakers area when wind is absent. All circuits and electric engines must be explosion proof.

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Appendix A shows an optimal land location arrangement. This example, however, is binding when the presence of H2S is ascertained (the reunion areas must be indicated by the Contractor Toolpusher).

INSPECTION/MAINTENANCE OF DETECTION/PROTECTION SYSTEMS Periodical inspection and maintenance of the monitoring and individual protection systems is the responsibility of the Drilling Contractor and of the Mud Logger (as far as the sensors are concerned). They must be carried out on the basis a maintenance schedule and criteria set forth by the equipment manufacturer/supplier. Such operations must be planned by the Toolpusher at the beginning of the drilling activity. A copy of the specific handbooks, reporting testing and checking procedures must be available at the rig and at the disposal of the Eni-Agip Drilling and Completion Supervisor. It is the duty of the Contractor's Toolpusher to make sure that all systems are kept in perfect working order. It is the duty of everyone provided with individual safety equipment to keep it clean and verify that the components are in working order. The following table provides an inspection and maintenance program indicating the maximum intervals for verifications. It is the duty of the Eni-Agip Drilling and Completion Supervisor to make sure that inspection and maintenance are carried out within the limits fixed by the table 10.bC below.

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Self breathing apparatus (3045min) Spare bottles Compressor Self breathing apparatus (10min.) Portable meters for H2S and SO2 Phials for H2S Phials for H2S Sensor for H2S in the air Acoustic and light alarm system Means of internal communication Explosion-proof electric torch

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DESCRIPTION

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TYPE OF INSPECTION

INTERVAL

Charge pressure, valve, masks, parts in rubber Valves Air filters, working pressure, oil and fuel levels Charge pressure, valves, masks, parts in rubber General conditions

15 days

Expire date Expire date functionally and adjustment Functionality

30 days 30 days 7 days 7 days

Functionality

7 days

Functionality

7 days

Table 10.B - Inspection/Maintenance Schedule

15 days 30 days 15 days 30 days

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APPENDIX A - H2S Detection And Danger Areas CONSTANT H2S DETECTION FOR LAND RIGS DESCRIPTION Equipment for the constant detection of H2S concentration consisting of: • •

QUANTITY

Unit with control panel and tool indicator of the H2S concentration Dependent on rig type with range capacity of 0-50ppm and two alarm levels (10ppm 20ppm) Dependent on rig type Sensors with short response time as per market availability

Portable detectors to measure H2S in the atmosphere (either manual or electronic). Colorimetric vials for H2S: 10 vials package. 1-200ppm 10 vials package: 50-500ppm 10 vials package: 100-2000ppm Colorimetric vials for SO2: 10 vials package: 1-200ppm 10 vials package: 20-200ppm 10 minutes Automatic Positive Pressure Escape Breathing Apparatus.

30-45 mins Self Contained Breathing Apparatus for land rig Extra cylinders for Breathing Apparatus for land rig 30-45 mins Self Contained Breathing Apparatus for off-shore rig Extra cylinders for Breathing Apparatus for off-shore rig AMBU type reanimator Battery operated portable explosimeter Wind sleeve Two tone alarm hooter Walkie talkie completed with batteries and battery loader Electric lamp (explosion proof type) Alarm flashlight Gas garret Train Test Kit or Hatch Test Kit H2S Scavenger for mud Fan

3 manual 2 electronic 10 5 5 5 5 30 for land rig 120% of the rig and supply vessel personnel for off-shore rig 15 45 120% of emergency team 3 spare bottles per breathing apparatus 2 2 2 2 6 6 2 red 2 yellow 1 (in sour area) 30kg/m 3 of mud 3

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Confined Location

ALTERNATE ROAD

BURN PIT

BARRICADE CAUTION SIGN WITH

BRIEFING AREA PROTECTION CENTER AND FLARE STACK (optional) FLARE

WIND STREAMER

PIPE RACK

REMOTE PREVENTER AND EQUIPMENT BLOW ACCUMULATOR STATION OUT

PIPE RACK

HORN LIGHT

SUB BASE STRUCTURE

SUB BASE STRUCTURE SHALE SHAKER MUD GAS SEPARATOR

MUD UNIT LOGGING

CHOKE MANIFOLD

MUD TANKS

MESS OFFICE AND/OR HALL SLEEPING QUARTERS

MUD TANKS

LIQUID (optional) KNOCKOUT DEGASSER

MUD HOUBE

RIG POWER PLANT PUMP PUMPPUMP

DIRECTION PREVALING WIND WATER TANKWATER TANKRIG FUEL FLARE BRIEFIND AREA PROTECTION CENTER AND ENTRANCE ROAD PIT BURN

WIND STREAMER

BARRICADE CAUTION SIGN WITH

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Unconfined Location

BURN PIT

ALTERNATE ROAD BARRICADE CAUTION SIGN WITH

WATER TANKS

RIG TANK FUEL FLARE RESERVE PIT

RIG PLANT POWER MIXING PUMP MUD HOPPER

MUD HOUSE

CHANGE HOUSE

PUMP PUMP PUMP

DEGASSER HORN CONTRACTOR'S TOOLPUSHER DRILLING OFFICEFOREMAN'S AND

MUD TANKS

LIGHT

SUB BASE STRUCTURE

SUB BASE STRUCTURE

FLARE

BURN PIT DOG HOUS SHALE SHAKER COMPANY HEAD QUARTERS

CHOKE MANIFOLD CATWALK

LIQUID (optional) KNOCKOUT

FLARE (optional) STACK

MUD GAS SEPARATOR BRIEFING AREA PROTECTION CENTER AND PREVALING WIND DIRECTION

PIPE RACK

PIPE RACK

BRIEFING AREA PROTECTION CENTER AND WIND STREAMER

MUD UNIT LOGGING

REMOTE PREVENTER AND EQUIPMENT BLOW ACCUMULATOR STATION OUT

ENTRANCE ROAD BARRICADE CAUTION SIGN WITH

WIND STREAMER

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Typical Land Rig Breathing Apparatus Locations

LEGEND = 30' - 45' SCBA. = 10' SCBA. = Wind Sleeve S = Sensor A = Alarm ring

Mud Mixing Area

Y = Yellow Flashing Light R = Permanent Red Light

S

Mud Pump Zone Mud Pit

Workshop

Substructure S

Rig Floor Bell Nipple A-Y-R

S

S

Derrick Board

Shaleshakers

Safety Material A-Y-R

Unit Mud Logging

Contractor's Office

Agip Office

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Emergency Form (To Be Filled When An Emergency Occurs On An En-Agip Rig)

EMERGENCY FORM TO BE FILLED WHEN AN EMERGENCY OCCURS ON AN ENI-AGIP RIG 01. HOUR / DAY: 02. WHO IS CALLING: NAME TELEPHONE 03. RIG NAME / LOCATION: 04. HOUR OF ACCIDENT: 05. NATURE OF ACCIDENT: FIRE, EXPLOSION, BLOW-OUT, POLLUTION, H2S, COLLISION, STABILITY PROBLEMS, UNCONTROLLED FLOATING, COLLAPSE OF HOISTING EQUIPMENT, RADIOACTIVE LEAKAGE, ACCIDENT TO A DIVER, MAN AT SEA, OTHER:

06. NUMBER OF PERSONS AT THE RIG: 07. NUMBER OF PERSONS WOUNDED: 08. NUMBER OF PERSONS MISSING: 09. DECEASED: 10. EXTENT OF DAMAGE:

11. EVACUATION / RESCUE: YES/NO HOW? 12. ACTIONS TAKEN ON THE RIG:

13. ASSISTANCE REQUIRED:

14. WEATHER CONDITION:

WIND :

VISIBILITY:

WEATHER: CLOUDS: SEA CONDITION: CURRENT: SEA TEMPERATURE: ENVIRONMENT TEMPERATURE: 15. ACTIONS TAKEN:

16. PARTECIPANTS: NAME NAME NAME 17. OTHER INFORMATION:

TELEPHONE TELEPHONE TELEPHONE

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Territorial Emergency Report

TERRITORIAL EMERGENCY REPORT

1. Date:

Hour:

2. Installation: 3. Nature of the accident:

Gas

Oil

4. Esteemed flow: 5. Blowout esteemed height: 6. H2S indication: 1. Danger area (300 m around the well over 360°) - H2S concentration: - SO2 concentration:

2. Health damage risk area (from 300 m to 1000 m around the well over 360°) - H2S concentration: - SO2 concentration:

3. Polluted area (over 1000 m around the well, over 360°) - H2S concentration: - SO2 concentration:

Water

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H2S Drill Report

H2S DRILL REPORT Eni-Agip Spv. and Rig Contractor Rep. must be awared of the Company H2S Procedures

Country ............... Field ..............

Well .................... RIG name.................. Rig Contractor ................... Rig Spt. ................... Driller ...................... Mudlogging .................... TDC .................... Mudlogger ................... Present Operation .......................................................... H2S sensor: Sh. shaker Rig Fl. B.O.P. Mud Pit Other Type of test: Weekly alert Emergency Programmed ................................... Date............. hrs.............. By .................................................................. (name and title of person starting the test) (hrs at the start test) Alarm from Mudlogging after min : ...... Alarm from Rig Fl after min: ........ Personnell on Rig Fl n°: .....

H2S ppm .... H2S ppm ..... Present .....

Alarm set @ ppm ............ Alarm set @ ppm ............ Absent ..... ...........................

Total time wear all the breathing apparatus: min. ...... Total time for meeting in safety area min: ..... Total time to put the well in safety condition: min. ..... BOP and Choke Mnfd. H2S Service? yes no ALARM SET UP: Well sketch 1st alarm Sensor: Sh. shaker Rig Floor BOP Mud pit CSG m O.H.

T.D. m

NOTE: bit depth at H2S drill m

Date of last test .............. 2nd alarm

Date of last test

........... ........... Alarm set up from instructions by: .......... Date: ....... Test of sensors:Metod ............................................... H2S safety equipment all present yes no H2S equip. in good condition and corrent location YES Expiring data fo filters, masks ect.: Expired n° ......

STOCKS Barite t. ......... Scavenger t. ........ Type ....................... Kill mud: kg/l ......... Volume mc................................ Skill level : Good Sufficent Poor Safety meeting after test? Yes no NOTE:

Test n°... Eni-Agip Spv. ............ Eni-Agip Spt.

.......................

Eni-Agip Drl. Manager...............

NO

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APPENDIX B - Bibliography Document:

STAP Number

Overpressure Evaluation Manual

STAP-P-1-M-6130

Drilling Procedures Manual

STAP-P-1-M-6140

ENI - Well Control Policy Manual

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