DOP 202 - Rev 2

Routine Drilling Operations Document No.

Document Title

DOP 202

Routine Drilling Operations

Page Rev No Date Doc No

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TABLE OF CONTENTS

1.0 2.0 3.0 3.1 3.2 3.3 3.4 3.5

4.0 5.0 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 5.9 5.10 5.11

PURPOSE.................................................................................................... 2 SCOPE......................................................................................................... 2 RESPONSIBILITIES...................................................................................... 2 Senior Toolpusher.................................................................................................. Drilling Supervisor.................................................................................................. Directional Driller.................................................................................................... Directional Surveyor/MWD Operator...................................................................... Well Loggers..........................................................................................................

2 2 2 2 3

DEFINITIONS............................................................................................... 3 PROCEDURE............................................................................................... 3 Handling, Making Up And Laying Out Bottom Hole Assemblies............................ 3 Tripping Procedures............................................................................................. 14 Drilling Procedures.............................................................................................. 16 Logging Operations.............................................................................................. 22 Casing Operations.............................................................................................. 31 Coring Operations............................................................................................... 36 Fishing Operations............................................................................................... 42 Well Testing Operations....................................................................................... 47 Well Completion/Workover Operations............................................................... 51 Well Suspension Or Abandonment...................................................................... 53 Directional Drilling Operations.............................................................................. 58

6.0 7.0

REFERENCES............................................................................................ 63 ENCLOSURES........................................................................................... 64

Rev No

Date

Prepared by:

Verified by:

1

15.03.96

CBA

WVE

Approved by: Safety and QA Managers AMO

2

12.03.99

IMI / LVA

ICO

BNO / AJE

G:\Management Library\Drilling Operations Manual\DOP202

Reason for Revision Issued for Implementation As per Procedural Review Scheme

Routine Drilling Operations 1.0

PURPOSE



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The purpose of this procedure is to describe and give guidance on routine drilling operations.

2.0

SCOPE This procedure is applicable on all Stena Drilling Units.

3.0

RESPONSIBILITIES

3.1

Senior Toolpusher The Senior Toolpusher is responsible for the implementation of this procedure.

3.2

Drilling Supervisor The Drilling Supervisor (appointed by Operator/Company, dependent on well contract type, normal or integrated service) has overall responsibility for correct implementation of directional drilling procedures that have been developed as part of the Well Programme. He is to liaise with all responsible personnel during the drilling operation to ensure compliance with directional drilling safety procedures.

3.3

Directional Driller The Directional Driller is responsible for drilling the well according to the Well Programme. He is to liaise with all personnel during the drilling operation. He is to ensure that the Drilling Supervisor is kept informed of all directional drilling matters. The Directional Driller is also responsible for performing directional survey calculations, proximity checks and ensuring that correct survey correction factors are applied to each survey in accordance with Well Programme requirements.

3.4

Directional Surveyor/MWD Operator These personnel are to take directional surveys as required by the Well Programme or as directed by the Directional Driller and Drilling Supervisor. They are to ensure that correct survey correction factors are applied to each survey in accordance with Well Programme requirements.

3.5

Well Loggers The mud loggers are to carry out independent directional survey calculations using correct survey correction factors as detailed in the Well Programme. This will enable directional survey calculations to be checked for accuracy. These calculations are only to be used to check the accuracy of calculations as carried out by the Directional Driller and Surveyors.

4.0

DEFINITIONS & ABBREVIATIONS




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None.

5.0

PROCEDURE

5.1

Handling, Making Up and Laying Out Bottom Hole Assemblies

5.1.1

Planning Prior to making up, breaking out, or changing a BHA, consideration should be given to the safest and most efficient method for constructing, changing, or dismantling the assembly. There is a vast selection of tools and equipment which require to be handled, and numerous methods for doing so, in general these can be broken down into five main categories: NOTE: 1.

The Driller shall alert the Duty Toolpusher before making up or breaking out bottom hole assemblies.

Tools with a lift recess can be put directly into the elevators by one of the following means: 2.

Full length tools over 8" diameter must be tailed in directly to the elevators or if fitted, use a catwalk machine..

3.

Tools 8” diameter or less can either be lifted into the mousehole using an air winch, the elevators can then be swung over using the DDM pipehandler to latch onto the tool, or they can be tailed in if desired. However, if fitted, use a catwalk machine.

The above procedures will generally relate to drill collars. 4.

For long tools without a zip recess, a lift sub must be fitted. This will generally relate to non-magnetic drill collars, jars, mud motors, MWD, core barrels, well testing tools etc.

5.

Tubulars or tools suspended on the elevators can be directly connected to another from: 6.

The mousehole (adjuster may be required depending on tool length).

7.

The Rotary table (Near bit tools).

8.

Placed on a Support pin fitted to the rotary table. NOTE:

This method is only suitable for tools with pin down connections which will not exceed a comfortable working height for the floormen. Under no circumstances should the pin be used to support a box connection.

Consideration could be given to fitting pin/pin x-over to box connections prior to picking up if the rotary table or mousehole is not available to handle them.




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The above methods will generally be suitable for shorter tools such as stabilisers, subs, crossovers etc. 4)

Lifted directly onto the string in the rotary table using an air winch and lifting cap, or manually for small subs and tools. Drill collar lifting subs will be handled using a set of single joint elevators fitted with a set of wire rope lifing slings. This will apply mainly to stab on kelly cocks, lifting subs, short subs which will remain within a reasonable working height when lifted into position, and various small diameter testing tools and crossovers. All lifting subs and crossovers will be screwed and unscrewed using chain tongs, after visually checking that both of the chain link pins are securely located in the tong lugs.

5)

Picked up from the derrick using a combination of racking arms depending upon configuration of the stand i.e. lift recesses, diameter, placement of stabilisers or other tools, location in derrick etc. Laying out or breaking down tools and tubulars may be performed as a reverse of above.

5.1.2

Preparation

5.1.2.1

Bit Selection And Gauging Factors that influence bit selection can be subdivided into three main groups which are, formation characteristics, operating practices and cost. Formation Characteristics: 1.

Formation Drillability Relates to the formation hardness characteristic. Apparent drillability usually decreases with depth due to increases in rock hardness (compaction) and to extraneous factors such as mud flow properties and poor hydraulics. Undercompaction generally increases drillability. Although this will not usually cause a change in bit selection, it often postpones to a deeper depth utilising the next harder bit type.

2.

Rock Hardness Relates to both compaction and the inherent compressive strength of the rock. Some types of rock such as limestone, chert and quartzite are harder than other at whatever depth they are encountered. Thus, they may require a significantly harder bit than the sands and shales drilled either above or below.


Routine Drilling Operations 3.


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Abrasiveness The presence of abrasive intervals may call for shorter, stronger teeth and special gauge protection. However, in unconsolidated surface sands, the tooth hardfacing on soft-formation bits usually lengthens tooth life sufficiently to make these bits the best choice despite the abrasive character of the formation.

Fractured rock is occasionally found in hard, brittle formations. It is troublesome because the rock tends to break into non-uniform large pieces that must then be ground up before the drilling fluid can carry them out of the hole. This usually results in severely broken teeth. Fractured intervals often require the use of bits with short teeth along with light force on bit. Too much emphasis cannot be placed on the proper selection of force on bit and rotary/DDM speeds. Unfortunately, there is no formula for determining the proper balance between weight and speeds since formation and bit types enter into this selection. Experience in a given area is the best guide, however, weight/speed optimisation finds the combination that gives minimum cost for a particular bit type. A drill off test should be carried out to find the optimum parameters. There are many different types of bits available from several different manufacturers with new types coming out frequently. Bit performance from offset wells and similar lithology will be evaluated and recommended bit selection shown in the drilling program. This should be followed unless hole conditions dictate that change is required. 5.1.2.2

Grading Used Bits The IADC has adopted a uniform code for grading mill tooth and insert bits. The Operator’s Drilling Supervisor will personally grade all used bits.

5.1.2.3

How To Ring Gauge Bits It should be standard procedure to ring gauge all bits-new or rerun bits before going into the hole and when the bit is in the dulled condition. If the gauge teeth of each cone contact the ring gauge the bit is said to be "in gauge". If however, contact by the gauge teeth is not made with the ring gauge, the out-of gauge condition is recorded showing the fraction of an inch under gauge.

5.1.2.4

Gauging Dulled Three-Cone Rock Bits Method One: 1.

Select proper ring gauge size. Gauge ID and tolerance should be stamped on ring gauge.

2.

With rock bit standing on pin, rotate cones so that the gauge points are at maximum bit diameter.

3. 4.

Pull ring gauge tight against the gauge points of two of the cones. Using a scale, measure the distance between the ring gauge and the gauge point of the third.




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5.

Multiply this measured distance by two-thirds to determine the amount undergauge.

6.

Record amount undergauge in the dull grading section of the bit record.

Method Two: 1.

Select proper ring gauge size.

2.

With bit standing on pin, rotate cones so that gauge points are at maximum bit diameter.

3.

Centre ring gauge over bit cones so that ring gauge ID is an equal distance from the gauge points of each cone.

4.

Measure distance from gauge points to ring gage.

5.

Since this is the radial distance, multiply this value by two to determine the diametrical amount bit is undergauge.

Due to their design, soft formation bits with high offset tend to drill over gauge holes in the softer rocks. Therefore, the bit may measure undergauge while the borehole will be in gauge or slightly overgauge. Hard formation bits with minimal offset are likely to drill a hole equivalent to the actual gauge diameters. 5.1.2.5

Gauging Diamond Bits: The gauge diameter for diamond bits is more critical since they are "fixed head" bits and do not have the "leg flexure" as with three - cone rock bits. When going into the hole with a diamond bit, it is important that the borehole diameter is known. Due to close clearance, diamond bits are manufactured with no overgauge to prevent damage to the bit or possible sticking in the hole.

5.1.2.6

Diamond Bits Drilling Principle Diamond bits remove formation by cutting, scraping and ploughing action, rather than by a crushing or chipping action. Thus, they are in effect a very expensive drag bit and to be effective they must be able to drill through long sections of hole at a drilling rate that makes them economically competitive with rock bits.


Routine Drilling Operations 5.1.2.7


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Weight And Speed Rotary/DDM speed is a major contributing factor to the rate of penetration for diamond bits. Test data indicates that with proper hole cleaning, the penetration rate is almost in direct proportion to rotary/DDM speed. High RPM will not burn a diamond bit if proper hydraulics are available to cool the diamonds and keep the cuttings removed. To achieve penetration of the diamond into the formation, sufficient force on bit must be applied. The rotary speed should be set and then a drill-off test run through a uniform formation to find the maximum force on bit compatible with available hydraulics. With diamond bits always run maximum RPM and force on bit allowed by hydraulics and string torque.

5.1.2.8

Operational Precautions Diamond bits are expensive drilling tools and can be easily damaged if improperly utilised. The following precautions should be observed before and when running a diamond bit:

5.1.2.9

1.

Run a junk sub one or two bit runs before a diamond bit run.

2.

Never drill on junk.

3.

Lower the bit to bottom without rotating and pump any junk or pieces of formation from below the bit. Minimum weight should be used until the bit is seated into the formation (first metre).

4.

Do not attempt to ream an excessive amount of undergauge hole as this may cause burning of the gauge diamonds.

5.

Bit failure is indicated by a pump pressure increase while drilling. This results from a ring of diamonds being destroyed which restricts the fluid passageway with the bit on bottom. This can be verified by checking on and off bottom pressures while pumping at a constant volume.

Polycrystalline Diamond Compact Bits Drilling Principle The polycrystalline diamond compact (PDC) is a one piece cutting tool. It consists of a thin layer of synthetic diamonds on a tungsten carbide disc. The tungsten carbide backing provides mechanical strength and further reinforces the diamond compact wear resistant properties. During drilling the (PDC) cutters wear down slowly with a self sharpening effect. This helps maintain sharp cutters for high penetration rate drilling throughout the bit’s life. This shearing action is the most efficient drilling mechanism in comparison with the compressive fracturing, gouging and grinding action of roller, cone and natural diamond bits. Considerably less energy is required to fail rock in shear than in compression. Thus it is possible to drill at high rates of penetration with (PDC) bits using lower weight on the bit, thereby reducing direct cost per foot while reducing wear and tear of the rig and drill string components.




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Due to less weight requirements, amount of drill collars are reduced and this results in less pressure loss through bottom hole assembly. 5.1.2.10

Drilling Procedures Before running a PDC bit the following precautions should be followed: 1.

Place a hole cover on the rotary table to prevent anything from falling down the hole.

2.

A junk basket run may be considered if there is any suspicion of junk in the hole.

3.

Do not roll the PDC bit on steel floor plates. Place a piece of plywood or rubber under it when it is stood on the cutters.

4.

Use a proper bit breaker by taking the recommended make-up torque and divide this by the length of the rig tongs to get the needed tong line pull.

NOTE:

Care should be taken when running the bit into the hole. After the bottom of the hole is located, the bit must be lifted from 0.5m (20") off bottom while circulating and rotating slowly for five minutes to make certain the bottom of the hole is clean.

•

Use light weight when cutting a new bottom hole pattern. Adding weight too quickly may overload and damage the cutters.

•

Once the bottom hole pattern is established, speed up the rotary/DDM to maximum 150 RPM and increase the bit weight until an acceptable rate of penetration is achieved. PDC drills better with lower weight on bit. After making a connection, the bit should be washed back down to bottom slowly at the full flow rate to clean any fill from the bottom.

One method of cleaning the bit is described below: 1.

Raise the bit off the bottom. Go back to just above bottom while running full pumps and normal rotary speed.

2.

Hold the bit for 10 - 15 minutes giving the fluid flow across the face of the bit an opportunity to clean the bit face while no new cuttings are being generated. NOTE: PDC bit drills best in soft to medium hard formations. It is very effective in deep drilling where the bottom hole temperature is high.




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By using oil base mud PDC bit tends to drill faster and last longer and are therefore recommended. However, certain shales which normally will require an oil base (inhibited) mud, can be more effectively drilled with a water base mud by using a higher bit hydraulic horsepower. 5.1.2.11

General Preparations 1.

8.

Check all handling equipment required (Ref. Checklist below): 2.

Elevators - visual inspection, check certification, function test and check safety catch. Test same for fit on drill collars.

3.

Slips - visual inspection, if necessary make up size required (Ref. Manufacturers Manuals).

4.

Visual inspection of lift subs and lifting caps.

5.

Safety clamp - (dog collar) visual inspection, if necessary make up size required (Ref. Manufacturers Manuals).

6.

Rig tongs - visual inspection, replace worn dies, inspect snub and pull lines, inspect tong pull sensor and check for leaks. Check spacer jaws available for different connection sizes.

7.

Iron roughneck - visual inspection, check jaws or spacers available for different connection sizes. Check torque calibration. Ensure all safety guards in place.

Lay

out and measure tools. The BHA configuration will be supplied/confirmed by the Operator’s Drilling Supervisor, and may include drill collars, non-magnetic drill collars, near bit and string stabilisers or roller reamers, jars, accelerators, MWD, downhole motors, x-overs, back pressure valve, bumper subs, etc. A bottom hole assembly sheet should be filled in noting the following information (Ref. Enclosure No 1).

9.

Thread type.

10. Individual tool length. 11. Cumulative length. 12. Bit type and diameter, nozzle quantity and size, serial number. 13. Fishing neck length. 14. If fishing tools available on rig. 15. Outside and inside diameters of tubulars. 16. Serial numbers. 17. Float type (ported or non-ported).




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18. Totco location. Also a visual inspection of threads and sealing faces must be carried out along with a check on any certification that is required.

5.1.3

3.

Drawings of stabilisers, jars, turbines/mud motors, MWDs and other specialised downhole tools should be made recording all relevant dimensions. This information may be required for any subsequent fishing operations.

4.

The drill bit should be prepared, and fitted with the required nozzles. (nozzles should not be hammered as they may shatter). If the bit is already dressed check the nozzles are secure, clear, and the correct size.

5.

Check gauge on drill bit, stabilisers and integral stabilisers on mud motors/MWDs etc.

6.

Service Engineers will supply any necessary information regarding make up torques or special procedures that may be required, e.g. surface testing turbines, mud motors, MWDs etc. Check if any intermediate connections are to tighten. Ensure crossovers required for use of the stab-in valve are ready on the rig floor before commencing the BHA handling operation.

7.

Prepare drifts that are required. It is good practice to drift tubulars as they are picked up to ensure no debris is lodged inside. Drift size will depend on the internal diameters. Always try to use the largest OD drift that will go through the tubular easily. If drifting tubulars as they are picked up, ensure that pin end protectors are intact and properly fitted to prevent the drift dropping onto the rig floor or catwalk as the tubular is picked up to vertical.

8.

Prior to picking up, laying down, or changing bottom hole assemblies, it is advisable to hold a tool box talk with Drill Crew and Deck Crew, making reference to the relevant sections of the BHA handling procedures. Discuss and agree on communications to be used between rig floor and Crane Operator, pointing out any particular hazards created by the equipment or particular operation. e.g. A bumper sub which is not fully open, may “drop” open whilst handling, causing an obvious danger to feet or anything else below it.

Picking Up/Laying Out 1.

There are several items to consider prior to handling drill collars, jars, mud motors, MWD casing etc. from the catwalk to the rig floor, these are: 2.

Drill collars up to 8” diameter can be lifted with a lifting cap and positioned in the mousehole using the manipulator arm. The catwalk tugger can be used if required to perform the tailing in function.

3.

Drill collars greater than 8” diameter must be tailed in (Ref. Section 5.1.1).




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4.

The weight of the equipment (to allow proper selection of adequate lifting gear).

5.

Lift recess - if the drill collar or tool has no lift recess it will be necessary to install a lift sub. After inserting the rabbit, the lift sub can be installed by one of the methods below: •

On deck - if weather conditions may cause problems with installation in the V-Door.

•

In the V-Door.

•

If the tubular is 8” diameter or less, it can be placed in the mousehole using a lifting cap and air winch. The lifting cap can then be removed and the lift sub installed.

•

Drill collars or tubulars, can be picked up and placed in the mousehole, or “tailed in” from the catwalk. For “tailing in” Manual elevators of the required type should be fitted to the elevator links. Picking up tubulars from the mousehole can be achieved using the DDM link swing in combination with automatic elevators.

General Guidelines for Tailing In are as follows: •

NOTE:

Attach rig floor airwinch to box end (use wire rope sling double wrapped and choked below the lift recess or lift sub, leave space for the elevators). Attach deck crane to a sling double wrapped and choked near the pin end. Raise the collar horizontally into the V-Door, guiding it into the elevators. If side door elevators are being used, the tool must be lowered in to the elevators and the elevators closed with the door uppermost. This will keep the load off the latch. If for any reason this is not possible, the air winch should be left attached and kept under tension until the tool is vertical.

If the above procedures require the use of centre latch elevators it may be necessary, in order to avoid the handles making contact with the elevator links, to use these elevators with the latch down. If this is the case, special care should be taken to check the operation of the safety latch. Under no circumstances should personnel be allowed to stand underneath whilst raising the tools to a vertical position. NOTE: 2.

To avoid damage to automatic elevators, these should NOT be used for tailing in.

Lower or raise the drill collar/tubular into elevators as described above, latch same visually, check that latch is fully engaged before removing airwinch wire and sling. Pick drill collar/tubular up with draworks and signal crane to “tail” drill collar/tubular in to rig floor under control. Unhook crane and remove sling.




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3.

On floating drilling units it is essential that tubulars are prevented from swinging due to rig motion. Use drill floor racking arm to steady tubulars, if this is not available then it may be necessary to rig up airwinches. (Once heavy tubulars are allowed to swing then it may be too late to prevent serious injury or damage occurring.) The protector can now be removed and the rabbit recovered.

4.

Ensure the pin and box are clean and doped with the correct lubricant, stab the pin into the box carefully. Avoid bouncing/dragging the pin on the box shoulder, it is essential to check for any damage if this should occur.

5.

It is good practice to “Walk in/Out” BHA tubulars using chain tongs, DDM/Top drive pipehandler rotation can be used (Ref. Operator Manual). Drillers should be aware of recommended make-up torque required on drill collars, bits, crossovers and other downhole tools refer to relevant service Company Representative if necessary.

6.

A float valve should be fitted in the near bit stabiliser or bit sub prior to making up the bit (assuming that they have the required recess bore). The float valve should be a snug fit and the seals on the body and flapper should be in good condition. The valve should be inserted fully before attempting to screw on the bit, under no circumstances should the bit shank be used to push the float home during make up. A totco ring of the crows foot design may be run on top of the float valve. The float valve must not be hammered home as this ring may dislodge and turn over. If the float valve has a mechanism to keep it open whilst running in the hole, this should be used to help minimise surge pressures and also remove the need for top filling the string. Ported floats allow the string to fill as it is run in the hole, but generally the flow rate through this small hole is insufficient to allow the string to fill quickly enough to keep up with pipe running speeds. If a trip is stopped under these circumstances the drillpipe will continue to fill from the annulus, therefore the hole fill pump must be running in order to keep the annulus full. Alternatively the string can be top filled.

7.

Making up or breaking off the bit will require the use of a bit breaker. This bit breaker in conjunction with a breaker plate fitted to the rotary table is the means to hold the bit whilst torque is applied. The rotary table may be locked either against the brake, or the manual lock depending upon the required torque value. (Care must be taken using the manual lock, rotation of the rotary may cause the lock to be kicked out if it is not fully engaged, this area is a pinch point and must be treated with caution.) The bit nozzles should be checked after the connection has been torqued to ensure that no damage occurred during the make-up process.



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Prior to picking up jars, the type should be identified and relevant information on strengths, maximum jarring loads, methods of operation, and any other checks which are required prior to make up and running in the hole should be identified. Clamps which are fitted should be checked to ensure they are secure prior to raising the tool to the vertical position. The clamp should be removed prior to running the jar in the hole, and refitted when it is pulled out of the hole. (Caution should be exercised when pulling jars through the rotary table as the mandrel may catch on the bushings causing them to lift unexpectedly.) Jars are normally supplied with a lifting sub, it may be necessary to removed this item to allow insertion of the rabbit.

NOTE:

9.


Due to internal profiles within the jar, the rabbit may temporarily lodge inside. A ball could be used if available. The weight of the bottom hole assembly below the jars should be recorded on the bottom hole assembly sheet along with the mud weight in use at the time.

Use safety clamp (dog collar) with all BHA equipment and ensure that it is in good condition and fitted correctly. DO NOT leave this on the tubular if it has to be lifted more than 2.5 - 3.0m above the rotary. Remove it and then refit same when required again.

10. Use iron roughneck (if available) to minimise hazards associated with rig tongs unless unable to fit same due to stabiliser blades etc. Driller to ensure that correct make-up torque is set and applied. 11. When using rig tongs observe safe working practices. 12. Whilst handling the bottom hole assembly, the location of the bit in relation to the BOP should be monitored. The compensator should be used whilst the bit is being run through the BOP. Whilst making up the assembly, the bit should not be allowed to sit in and reciprocate through the BOP with rig heave, it may damage the cavities, or even cause the assembly to be lift unexpectedly through the rotary table. 13. The diverter insert packer will have to be removed for running or pulling large diameter bottom hole assemblies, it must be removed prior to pulling the bottom hole assembly, and replaced as soon as possible after running a bottom hole below the rotary table. A board showing the current status of the packer i.e. in/out must be kept up to date, and in view of the Driller. 14. Well is to be monitored on the trip tank and a trip sheet kept at all times. 15. Drill collars/tubulars etc. can be laid out using the reverse of the above. Tubulars laid out should be cleaned externally and internally. Threads should be cleaned, doped, and have protectors fitted before being racked or loaded for return to shore. Internal cleaning can be achieved by pouring a small amount of base oil or fresh water as appropriate into the string before pulling out. 16. Driller/Assistant Driller/Crane Operator must ensure that any tubulars moved from deck to rig floor, rig floor to deck and around the deck have appropriate thread protectors installed.


Routine Drilling Operations 5.1.4


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Tripping B.H.A. In/Out From Derrick 1.

Use automatic elevators, lift subs and pipe handling equipment as much as possible to enhance safety and efficiency. Take due care and attention when using automatic elevators with light loads (Ref. Manufacturers Manuals).

2.

Gauge all stabilisers on trips in and out of the hole. Note any changes and report same to Senior Toolpusher and Operator’s Drilling Supervisor.

3.

Before racking jars in the derrick, the safety clamp should be fitted. As these clamps are normally light alloy care must be taken to prevent them from striking other tubulars, catching on the racking arm head, or intermediate board. The jars should always be packed on the top of a stand.

NOTE: 4.

Damage may result in pieces falling to the rig floor.

Well is to be monitored on trip tank and trip sheet kept (see Enclosure 2). Compensator to be used for passing the bit through the BOP and wellhead.

5.2

Tripping Procedures

5.2.1

Running In The Hole 1.

BHA Handling (Ref. Section 5.1).

2.

Install diverter insert packer as soon as possible - at first joint/stand of heavy-weight drill pipe. Check that lock-down dogs are engaged.

3.

It is good practice when running diamond/PDC bits to run a pipe wiper below the rotary table. Ensure that it is large enough not to be taken downhole by tool joints.

4.

Stab-in valve to be kept readily available at all times for easy stabbing/make-up to drill string. Driller to have regular drills to ensure crew response is swift and effective.

5.

Carry out any planned maintenance with bit inside the casing shoe before running into open hole - slipping and cutting drilling line, lubrication of DDM etc.

6.

Monitor well on trip tank and trip sheet to be kept (see Enclosure 2). Do not trip pipe whilst pumping out trip tank. This will ensure an accurate record of displacement is kept.

7.

Driller must ensure that correct make-up torque is applied to drill pipe.

8.

It may be necessary to stop and fill the drill string when using a float valve. This should be done every 3000 ft and volumes should be tallied up to ensure correct displacement. It is very important to minimise the amount of air trapped in the drill string when circulation is started.




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Running speeds should be chosen for the prevailing hole conditions. Be aware of surge effects etc. and should hole problems/incorrect displacement occur then Senior Toolpusher and Operator’s Drilling Supervisor should be notified.

10. Assistant Driller/Derrickman should check that mud pumps are lined up ready to circulate through the string before reaching the bottom of the well. It is advisable to have this done before the bit goes into open hole in case of hole problems. Shakers/mud cleaners should be started approximately 5 - 10 minutes before breaking circulation if possible. 5.2.2

Pulling Out Of Hole 1.

Circulate bottoms up/hole clean as directed by Operator’s Drilling Supervisor/Toolpusher/Mud Engineer.

2.

Establish TD with zero weight on bit. It will be necessary to include a correction for tide on floating drilling units.

3.

Flow check well - 10 minutes minimum. Reciprocate pipe to prevent string getting stuck.

4.

Prepare and take deviation surveys if required (Ref. Well Programme).

5.

Hole conditions will determine when to “slug” pipe. It is advisable to pull pipe “wet” using a mud bucket where there is the possibility of having to pump out/backream. Assuming conditions are good, slug pipe.

6.

Line up well on trip tank and start re-circulating pump. It is recommended that AD carries out a visual inspection of the system to identify/isolate any leaks. Trip sSheet to be completed (see Enclosure 2). Drainage from the mud bucket must be returned to the trip tank.

7.

Pull out of hole. Pipe speed is dependent on hole conditions, swabbing effects. If hole problems/improper fill occurs then notify Senior Toolpusher and Operator’s Drilling Supervisor without delay.

8.

Install pipe wiper(s) below rotary table when hole conditions and hole fill are good.

9.

It is good practice to break different connections at each trip. Trips can be made on “stand/double/single” to achieve this. These operations to be logged on IADC report.

10. Stab-in valve and key to be readily available at all times for fast stabbing/make-up to drill string. Regular drills to be carried out inside casing to ensure proper and quick responses by drill crews. 11. Flow check well at casing shoe and before pulling BHA into BOP, and any other time there is doubt. 12. Remove pipe wiper(s) and if necessary the diverter insert packer before pulling BHA through the diverter.

5.3

Drilling Procedures



5.3.2


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Starting Drilling 1.

It is recommended to break circulation and wash/precautionary ream to bottom (at least last stand with top drive). Break circulation slowly to ensure that any pressures needed to break gels do not break down formation. Rotating the string will assist to break gels before commencing pumping. Ensure that there are good returns before going on bottom.

2.

Remove any pipe wiper used during RIH and install bushing protector used with DDM. Alternatively have 2 sets of bushings, one for drilling and one for tripping, (wear on the drilling bushings must be monitored).

3.

Measure in on pipe from convenient reference point and tag bottom carefully. Note any fill, report same on IADC Report.

4.

Record slow circulating pressure (Ref. Well Control Manual WCO 200).

5.

Break in bit as directed by Operator’s Drilling Supervisor, Toolpusher or Bit Manufacturers Guidelines.

6.

Run mud degasser during first circulation (at least bottoms up) in case of trip gas. Set up alarms/counters to alert Driller in advance of anticipated bottoms up.

Drilling Ahead 1.

Drilling parameters will be determined by hole size/conditions, bit type etc. (Ref. Well Programme, Toolpushers and Operator’s Drilling Supervisor).

2.

Shaker House to be manned at all times during circulation. Shaker hand must report any observed mud flow variations to the Driller immediately.

3.

Derrickman will monitor mud pumps, mud volumes and mud properties as required. He must report any variation in volumes or critical mud properties (e.g. mud weight) to Driller, Toolpusher and Mud Engineer immediately.

4.

Assistant Driller will check on 2 and 3 on a regular basis to ensure that vigilance is maintained.

5.

Connections will be carried out as per DDM Manufacturer’s Operating Manual. Washing or backreaming will only be carried out if hole conditions require. Driller must notify Toolpusher and Operator’s Drilling Supervisor when experiencing hole problems. Connections should be made in a safe, organised and efficient manner to minimise time spent with string static.



5.3.3


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6.

It is recommended that sufficient drill pipe is made up and racked in the derrick to drill the next hole section, (minimum - anticipated bit run). This will avoid potentially hazardous operations when making up stands in the mousehole during drilling operations. Procedures will depend on specific installation layout and be the result of discussion between Rig Manager, Senior Toolpusher and Operator’s Drilling Supervisor.

7.

Well Control must be maintained as per Well Control Manual (Ref. WCO 200).

8.

Safe, efficient drilling operations will result from good communication between Driller/Rig Floor/Shale Shaker House/Mud Room(s) and Mudlogging Unit.

Deviation Surveying Purpose Of Deviation Control 1.

To avoid abrupt changes in hole angle that may: 2.

Cause cyclic fatigue in the drill pipe and drill collars.

3.

Cause heat cracking in tool joints.

4.

Cause excessive wear in the subsequent casing strings while drilling.

5.

Hinder running of casing or formation evaluation tools.

6.

In special cases, control the direction of the hole to achieve a specific bottom hole location.

7.

To enable side-track of a fish (Ref. 5.7 on Fishing).

8.

To avoid excessive drag , torque, and key-seating problems:

Survey Types Survey type and frequency will be specified in Operator’s Well Programme. Ssurvey tools can be divided into 2 categories: 1.

4.

Dropped into string and retrieved using overshot for example: 2.

Magnetic multi-shot.

3.

Totco single shot drift indicator.

Run on wireline with surface read-out for example: 5.

Gyro surveying tools.

6.

Steering tools.

7.

Run as part of BHA and data transmitted to surface (e.g. MWD teledrift).




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Particular tools are used during different drilling operations. More details (Ref. DOP 20Section 3), where likely survey operations have been assigned to particular well sections. Driller must check that fishing equipment is available and checked for operation before dropping single or multishot type instruments into the drill string. It is important to consider several factors when running wireline inside the drill string: 1.

Potential well control requirements.

2.

Potential sticking of drill string.

3.

Outside diameters of tools and overshots in relation to drill string inside diameters.

4.

Damage to drill string by wireline - threads on top connection etc.

5.

Safe working with sandlines/slicklines/electric lines.

NOTE: 5.3.4

5.3.5

A suitable wire line cutter must be available on the rig floor at all times when wirelining.

Causes Of Hole Deviation 1.

Formation properties/dip.

2.

Improper mechanical arrangements of Utilising wrong drilling parameters.

3.

Drilling of cement plugs in open hole.

the

bottom

hole

assembly.

Drilling Straight Holes 1.

Side-stepping is a problem prevalent in large holes with alternating hard/soft formations or fractured/broken formations. The problem is more severe in anthracite and limestone’s. Drill with stabilisers above the bit and in the string to minimise the side-stepping problem.

2.

To counteract angle increase due to dipping formation:

5.

3.

Restrict the rate of angle change with a "packed BHA".

4.

Hold or drop angle by converting the BHA to a pendulum type.

The packed BHA includes one near bit stabiliser, one drill collar (short or normal length) one string stabiliser, one drill collar, one string stabiliser and then drill collars. In areas where angle change is a severe problem one can use the maximum packed BHA including one nearbit stabiliser, one string stabiliser, one drill collar, two string stabilisers and then drill collars.



5.3.6


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6.

A typical pendulum BHA consists of bitsub, two drill collars, one string stabiliser and then drill collars.

7.

Packed BHA should be run with high RPM and high WOB.

8.

A pendulum BHA should be run with low WOB and high RPM.

Operational Guidelines For Directional Control 1.

Alternative survey instruments to check instrument accuracy.

2.

Backreaming to reduce angle is acceptable, but precautions must be taken to avoid unscrewing the drill pipe if there are doglegs in the hole. Do not stop DDM abruptly. Slow down gradually before stopping.

3.

In general, attempt to avoid hole angles in excess of seven degrees.

4.

Be cautious about running junk subs or shock subs in crooked hole formations.

5.

Dull bits contribute to an increase in hole angle in crooked hole formations.

6.

Deviation in the 36” hole should not exceed 1º. When jetting in the casing, survey prior to releasing from the casing.

7.

Avoid abrupt changes in hole angle or direction 100m (330 ft) above and below the casing setting depth.

8.

The Operator’s Drilling Supervisor will personally read all directional surveys and insure that the results are recorded and reported.

9.

Straight holes will be surveyed at least every 100m (330 ft) but this interval should be adjusted depending on the dip anticipated, history of offset wells, and on-site circumstances (e.g. a zone of unusually high torque might indicate a fault).




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Stabilisers And Their Use Stabilisers placement and bit weight are used for building, holding and dropping angle. Weight on the bit causes and forces the collars to contact the low side of the hole. The distance from the bit to the point the collars contact the side of the hole is called the point of tangency. This distance is a function of collar OD, diameter of the hole, and the amount of weight applied to the bit. When a stabiliser is run below the point of tangency, it acts as fulcrum and causes the hole to increase in angle. By increasing the bit weight, the fulcrum effect is multiplied, thus causing the hole to have a greater tendency to be deflected. Drilling with low WOB, with a stabiliser at or above the point of tangency, the stabiliser produces a pendulum effect. This effect holds the collars off the low side of the hole so that gravity acts upon the mass of the columns, tending to pull it back to vertical and thus tends to straighten the hole. Important Points For Usage Of Stabilisers 1.

All stabilisers will be full gauge if special control is not needed. Stabilisers worn 3.2 mm (1-1/8") or more will be laid down and repaired.

2.

Stabilisers should be gauged each trip when directional control is imperative.

3.

The entire bottom hole assembly shall be magnafluxed between wells if high angle holes are being drilled, otherwise every 6 months approximately.

4.

The shoulder on the top of the stabiliser blade should be tapered 45º or greater.

5.

Coarse cluster-rite on the blade face is not permissible.

6.

Stabiliser terminology:

9.

7.

Open design - (vertical holes) - 3 blades have a wall contact of 140º.

8.

Closed design - (deviated holes) - 3 blades have a wall contact of 360º.

When conditions exist conducive to developing keyseats, a stabiliser (360º) run at the top of the collars is often helpful.

10. Dependent on operation and requirements of Directional Driller, tThe bottom three joints of collars may should be stabilised for directional control. 11. Integral, sleeve, and welded blade stabilisers are available. Integral type is preferred. Welded blade stabilisers shall be properly stress relieved. Integral blade stabilisers only will be used in 12¼" holes and smaller. 12. The inside diameter of the stabiliser shall be the same as the inside diameter of the drill collar string. Stabiliser connections shall have stress relief grooves.




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13. The near bit stabiliser shall have an API Reg. box down with the bottom of the blade no more than 30 cm (12") from the box shoulder and it shall be bored for float. High Torque 1.

Stabilisers are often the source of high torque. Generally torque developed by stabilisers will fluctuate widely. The commonly accepted methods of controlling stabiliser torque are: 2.

Replace most of the drill collars (and stabilisers) with heavy-weight drill pipe.

3.

Use roller reamers. These stabilisers are generally acceptable for straight holes, but have a short life span in some formations.

4.

Use a mud motor/turbine.

5.

Reduce rotary/DDM speed.

6.

Treat the drilling fluid.

7.

Restrict the drilling torque to the make-up torque applied to the weakest connection in the drill string, less an amount for inertia effects (weight and speed of rotation).

8.

The torque meter should be calibrated at least once per well as follows: 9.

Latch the drill pipe tongs around the tool joint on the drilling stand.

10. Make sure the tong line is at a 90° to the tongs. 11. Make sure the tong torque gauge has been recently calibrated. 12. Gradually increase the current to the rotary/DDM motor. 13. Note the amperage reading and tong torque as the tong torque increases. 14. Tabulate amp versus torque. 15. Check tong torque versus rotary/DDM torque on the Driller’s console. 16. Calibrate the torque gauge on the Driller’s console if required. 5.3.7

Side Tracking There are several techniques and tools which can be used to intentionally deviate the wellbore. The most common way to do this is by the use of a mud motor and a bent sub. Correct initial deflection and direction are essential at the start of directional drilling. Therefore a determining factor in the success of the operation is to select the "best kick off point" or depth at which the directionally drilled section is to be started.




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The following is a description of the most frequently used deflection tools and methods: 1.

Down Hole Motor Method With Bent Sub This method uses a down hole mud motor and a bent sub to obtain the desired deflection and direction. The tools are run in the hole and orientated. Each mud motor will have a specific response to the volume of mud pumped through it (RPM volume). After the tool has been oriented the rotary or DDM is locked. A pumping rate is established to give the desired RPM and the bit is lowered to the bottom of the hole or to the top of the kick off cement plug. Corrections will have to be applied at surface to compensate for twist in the drillstring due to reactive torque. Drilling proceeds with surveys normally made after each joint of pipe has been drilled. Drilling is continued until the desired deflection has been obtained. The mud motor is pulled and a stabilised drill string is run back in the hole to drill ahead. Orientation and surveying will normally be done using either a MWD tool or a steering tool. While the MWD tool sends information to surface through pressure pulses through the mud, the steering tool needs a single conductor wireline. To avoid pulling the probe each time a connection is made a wireline entry sub can be used. The angle changes induced when using a downhole motor are in the form of smooth curves rather than abrupt doglegs. They permit the use of full gauge bits which can be followed with a normal drilling assembly. Course correction, if required can be made downhole without making a trip.

2.

Undersized Collar Method This method of sidetracking uses 6" drill collars below 8" or 9½" drill collars. There should be three drill collars between the near bit stabiliser and the string stabiliser. Low RPM and high WOB are to be used.

3.

Other Special Considerations If kicking off on a cement plug, it is important to have hard cement. Hole and mud conditions will dictate amount and composition of cement etc. When side-tracking because of fish, the new hole should be far enough from the old hole to prevent contact with the fish.

5.4

Logging Operations

5.4.1

Responsibilities The Clients Representative is responsible for issuing the instructions to commence logging operations.




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The Logging Engineer is responsible for carrying out the logging operation in accordance with the agreed company procedures. He will raise a permit for use of explosive or radio active sources, and ensure that radio silence/top drive isolation is requested if required. He is to keep the “on-tour” Toolpusher informed of the progress and to ensure all necessary safety practices are adhered to. 5.4.2

Preparations 1.

Restrict crane operations during wirelining to avoid collision between load and wireline. Urgent lifts should only be done when tools are out of the hole and following discussion between Toolpusher, Operator’s Drilling Supervisor, Logging Engineer and Crane Operator.

2.

To ensure hole conditions are good for running logs, it is normal practice to make a wiper trip and then circulate the hole clean. The mud properties can also be adjusted as required for logging tools to be used.

3.

If required, strap the pipe whilst POOH to run logs.

4.

Assistant Driller must ensure that equipment required to rig up and run logs is ready before BHA is out of the hole.

5.

Discuss with Logging Company Engineer/Operators regarding: 6.

Space required on deck for preparing/testing tools.

7.

Number of runs to be done and types of tools to be used.

8.

Precautions to be taken - radioactive sources/explosives etc.

9.

Time required to get tools ready on catwalk during POOH with drilling/wiper assembly.

10. Tool lengths and diameters must be known. 11. All fishing tools required are available on the rig. 12. Pressure control equipment such as a stuffing box should be available on the rig. 5.4.3

Rigging Up On floating installations it is necessary to rig up a heave line from the riser slip joint over a sheave on the DSC/DDM and down to a shear link attached to the rig floor. Actual rig up will vary from unit to unit. Ensure that all shackles used are tightened completely and secured with wire if necessary. Fit a short safety sling across the shear link to prevent the compensating wire flying free in the derrick if the link should shear.




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Fully stroke out the compensator with low air pressure, lower the elevators and rig up the logging equipment. Disconnect the air line and secure the latch on the elevators. Pick up the blocks and logging equipment until near required height. Do not bring the compensator to mid stroke until the logging tools are safely below the rotary. If compensator heave line sheave is positioned above elevators, change auto elevators out for manual 5" elevators to avoid damaging latch piston with heave line. Do not exceed 15,000 lbs pull on compensator. Electrically isolate DDM if handling explosive tools while tools are on rig floor. Maintain close watch on DSC pressures to ensure that proper compensation is given to logging string, this is especially important when there are hole problems and good communication between logging unit and drill floor is essential. Drill Crew will assist Logging Crew to make up tools as required, operating airwinches, steadying tools when stabbing but final make-up is the responsibility of the Logging Engineer/Operator. Good communication between Logging Engineer/Operator and Drill Crew is essential for safe and efficient working. A line wiper must be fitted prior to pulling wireline from the well. 5.4.4

Logging Tools The following is a brief description of wireline logging tools and their intended use.

5.4.4.1

Formation Resistivity Induction Log •

This electromagnetic device is used to determine formation resistivity.

•

A dip induction log responds to formations beyond the radius of 1m (3 ft). The area is normally uninfluenced by drilling fluid invasion.

Laterolog •

5.4.4.2

This log is a focused current device and is used to measure formation resistivity. This tool performs best in a salty drilling fluid in medium to high resistivity rocks.

Porosity Sonic Log This tool measures transit time of sound compression waves. This property of rock correlates satisfactorily with porosity in clean well compacted sands. The sonic log only investigates rock approximately 2.5 cm (1") from the wall of the hole. However, the measurement is relatively insensitive to mud cake and washed out sections.




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Density Log This radioactive tool bombards the formation with gamma rays and measures the formations ability to absorb these gamma rays. The ability to absorb these rays is related to formation density. With knowledge of type of formation rock, porosity can be calculated from density. The density log rides the wall of the borehole and compensates for the filter cake, but is not reliable in washed out hole. Lithodensity Log The lithodensity log has in addition to the conventional density curve a Pe curve which is an index of the effective photoelectric absorption cross-section of the formation. The curve is sometimes helpful in determining variable lithology. 5.4.4.3

Neutron Log This is also a radioactive logging tool. The device continuously bombards the formation rock with neutrons and measures the rocks ability to slow or capture the neutrons. This slowing or capturing ability is a measure of the water or oil content. This tool rides the wall of the hole and the compensated neutron log, compensates effectively for filter cake and washed out boreholes.

5.4.4.4

Combination Logs Induction - Sonic Both induction and sonic devices are combined in one tool and log simultaneously to save rig time. Density - Neutron Both the density and CNL are combined to make a single tool.

5.4.4.5

Other Logs Micro-Resistivity Logs These devices are wall riding tools designed to read the resistivity of the invaded zone. The resistivity measurement is read 15 - 25 cm (6 - 10" into the formation rock). There are four tools used for this purpose: •

Microlog.

•

Microlaterolog.

•

Proximity log.

•

Microspherical focused log.

Spontaneous Potential




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The spontaneous potential (SP) is a measure of contrast of mud salinity and formation water. The SP Shows maximum deflection in one direction for clean sands and in the opposite direction in clean shales. The SP is usually run as an additional curve on resistivity logs, sonic logs and as depth correlation in tools such as sidewall core guns and wireline formation test tools. Gamma Ray The gamma ray (GR) log measures natural gamma ray radiation of the formation. The GR-reading is highest in shales and lowest in clean sands or carbonates. Natural Gamma Ray Spectroscopy Log The natural gamma ray spectroscopy log detects naturally occurring gamma rays of various energies emitted from a formation. Thorium, uranium and potassium (Th, U, K) are primarily responsible for the energy spectrum observed by the tool. Caliper A caliper log is a measure of hole size. On the sonic log, the hole size is derived from a three-arm centraliser. On density and micro-resistivity log, the caliper is derived from a deflection between a single backup arm and the tool. This two-arm calliper is often different from the three-arm caliper when measuring eggshaped holes. A dipmeter log can provide four pads, thus two separate calipers are shown. Uses of the caliper log include distinguishing porous rocks from shale, hole volume calculation, and correlation between logs. Dipmeter Logs Modern dipmeter tools consist of four pad-type micro-resistivity logs and a highly accurate system of measuring tool deviation from vertical, hole drift azimuth, and compass bearing of the pads. Uses of the dipmeter logs include structural mapping, location of faults, non-conformities, folds and bedding features that permit interference of environment within which the beds were deposited. Velocity Survey A velocity survey is performed by locating a geophone at several stations in the well and recording the response when an energy source is triggered at a surface location near the well.




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Vertical Seismic Profiling A VSP is performed by locating a geophone at several stations in the well and recording the response when an energy source is triggered at a surface location near the well. The data recorded by the geophone is processed by a computer to obtain information similar to a seismic section. Reflections from horizon below the present well TD could be detected. Proximity Survey This survey is similar to a velocity survey system except that several carefully selected surface locations are used with the energy source. The energy sources are rigged separately. Ultra Long Spaced Electric Log The ULSEL is a very long spaced conventional electric log with electrodes on a logging cable spaced from 200 - 800m (650 - 2625 ft) apart. Formation Tester The Repeat Formation Tester (RFT) is the wireline formation tester most widely used. The RFT may be set any number of times during a single logging run. At each setting depth, a "pre-test" is made in which small samples of fluid are withdrawn from the formation. During the pre-test the fluid pressure in the formation adjacent to the wellbore is monitored until equilibrium formation pressure is reached. These RFT pressure data are recorded at the surface. The "pre-test" fluid samples are not saved. However, after the pre-tests in a zone of interest, another larger fluid sample can optionally be taken and retained, with the possibility of retrieving two such fluid samples per trip in the hole. One of the original purposes of the pre-test was to assure a good retrieved sample by making a preliminary test for the hydraulic seal and to ensure sufficient permeability. This is accomplished by monitoring the pressure at the surface as small "test" samples of fluid are withdrawn from the formation. However, the pre-test is very useful in its own right as a pressure measuring test. Upon setting the tool, the pre-tests are automatically and sequentially activated. The low flow rate pre-test (Chamber No 1) withdraws 10 cc of fluid from the formation by movement of a piston in the pre-test chamber. This is followed immediately by the second pre-test which withdraws another 10 cc at a high flow rate. The ratio of the flowrates in the two pre-test periods is approximately 1.0 to 2.5. Since the pre-test withdraws only 20 cc total fluid, the fluid is essentially all mud filtrate. The pressure gauge is located in the flow line downstream of the filter probe. During a pre-test the pressure drop in the flow line is essentially negligible and the pressure indicated by the gauge is that the formation face.




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The pressure is initially at hydrostatic mud pressure. When the packer first engages the filter cake, the pressure may rise due to packer or mud compression, followed by a drop due to the retraction of the filter-probe piston. When the piston stops, the pressure builds up due to continued compression of the packer but suddenly drops again at the start of the pre-test. At time, T1, the piston in Chamber No 1 is fully withdrawn, and the first pre-test is complete. It is immediately followed by the higher flow rate and hence a larger pressure drop of the second pre-test. At time, T2, the piston in the second chamber is fully withdrawn, and the pressure builds up to formation pressure 0. The fluid samples can be taken at any setting and they can be recovered immediately (transferred at atmospheric pressure) or, alternatively the sample can be sealed and have a PVT transfer at later date. Note that transfer of sampling fluid using mercury as the displacing fluid, is restricted by NPD. If RFT is run in 8-3/8" hole or less spare cable should be mobilised. 5.4.4.6

Cased Hole Logs Neutron Log This is similar to a neutron log run in open hole. Generally the effects of pipe and cement make determination of porosity less reliable than in open hole. Pulsed Neutron The pulsed neutron tool emits high energy neutrons on an intermittent basis, then detects radiation response die away between pulses. This permits calculation of water saturation and distinction of oil from gas under many conditions. Cement Bond/Variable Density Log The cement bond/variable density log is used to determine the quality of the cement to casing bond around a cemented casing. The cement bond log records the amplitude, in millivolts, of the first half cycle of an acoustic signal at a receiver located 3 ft (1m) from the transmitter. This amplitude is maximum in unsupported and minimum in well cemented casing. The variable density log records the waves train from the acoustic pulse at a receiver which is 5 ft (1½m) from the transmitter. The shape of the wave train is used to determine the quality of the cement bond. When the cement is bonded to pipe, there will be transfer of sound energy from pipe to cement, and the casing arrivals will be weak. The sound travelling along the cement will be attenuated. If the cement is well bonded to the formation, energy will be transferred to the formation, and strong formation signals can be expected. In free pipe most of the sound energy will travel via the pipe, little of it being transferred to the cement or formations.




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Temperature Log The temperature log is used to locate the top of the cement after a cement job. The heat generated by the setting cement increases the temperature inside the casing by several degrees over normal. The temperature change at the cement top is identifiable on a temperature log provided the log is run at the proper time (8 - 10 hrs) after the cement job. Cement Evaluation Tool The CET is a high frequency ultrasonic device with eight focused transducers examining different azimuths of the casing with very fine vertical resolution, thus enabling a channel to be identified. The transducers act as transmitters and receivers, each transducer emitting a short pulse of acoustic energy and then receiving the echo from the casing. The short, light, rigid sound is centralised easily. The type of wave propagation used (compressional wave normal to the casing surfaces) is not affected by a microannulus that is small with respect to the wavelength. Reflections from the formation arrive later than from the cement and thus can be distinguished. The response of the tool is dependant on the acoustic impedance (product of density and acoustic velocity) of the cement, and an empirical relationship has been established experimentally between this elastic parameter and the compressive strength for oilwell cement. Thus the log can be calibrated directly in cement compressive strength. Also the azimuthal separation of the transducers enables a pictorial representation of cement distribution around the casing. The basic idea is to make the casing resonate in its thickness mode. The presence of cement behind the casing is detected as a rapid dampening of this resonance, while a lack of cement gives a long resonance decay. The interpretation of CET is simpler than CBL. Channelling and gas migration can fairly easily be identified. 5.4.5

Logging 1.

The trip tank will be used to monitor the fluid level in the hole during logging operations. NOTE:

Depending on hole clearances swabbing can occur with wireline tools.

The amount of mud displaced by various sizes of logging cable is as follows: Cable Diam: 7/32” 15/32”

m³/1000m

BBL/3300 ft (approx)

0.0242 0.1119

0.153 0.704




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Mud checks are to be carried out on active and reserve mud tanks at regular intervals and the Mud Engineer should run regular checks on mud being circulated across well from trip tank. Log mud weights and viscosity’s on IADC Report.

5.4.6

2.

The mud level in the trip tank should be lower after each logging run than it was at the start of the run. This is due to fluid loss to the formation and surface loss through the wireline wiper. Anytime the fluid level is higher than when the logging run began, the well is either flowing, has been swabbed, or fluid has been added at the surface. A line wiper should be utilised on the logging line rather than washing the line with a water hose.

3.

The Logging Engineer must be instructed to be alert and report any unusual hole conditions such as drag, bridges or sticky hole. If there are problems, consider to make a wiper trip.

4.

The Logging Engineer must also be instructed not to pull out of the rope socket if logging tools become stuck. When logging tools are stuck in the hole the recommended fishing procedure is to "cut and thread" with an overshot.

5.

Logs should always be recorded on the way down in case tools get stuck or other problems are encountered on the way out.

6.

When running side wall cores it is important to start at the bottom and proceed upwards.

Logging Problems These can be divided into 2 categories: 1.

Unable To Go Down In this case it may be necessary to try different configurations of tool string, remove stabilisers if fitted and add a hole finder. If the problem still continues then it may be necessary to make a wiper trip. Ensure that the Logging Engineer reports any unusual hole conditions with relevant depths so that the area of hole can be worked.

2.

Tools Stuck These can usually be recovered using a cable head overshot in conjunction with a spear head overshot. The cable head overshot is made up on the bottom of the fishing string and then stripped over the logging cable. Prior to this the logging cable is cut at surface (with due regard to tide and tension requirements), and a spearhead overshot assembly is rigged up to each end of the cut point to provide a quick surface connect/disconnect while making up and lowering each stand during the “cut and thread” operations. A successful “cut and thread” is achievable with: 3.

Good communication between Logging Unit Winch Operator and rig floor.




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4.

Proper briefing of crews before starting. Ensure that personnel are aware of procedure to use if well control is required. Methods used to get stab-in valve installed.

5.

Prepare a plan of action based on estimated depth where tool is stuck. Discuss with Logging Engineer any space out, tools required and ensure everything is ready on the rig floor in plenty of time.

5.5

Casing Operations

5.5.1

General Preparation 1.

Lay out casing on the rack as soon as it is loaded on board. In the case of tapered/combination strings, it is important to identify grade and weight of each joint and rack them to ensure that First items to be run will be at the top. Rack casing with wood stripping between layers giving at least two points of support.

2.

Check proper fit of side door and single joint pick-up elevators around some joints of casing. Check certification up to date. Check condition of latches, safety pins etc. Check Condition of slings/swivels/bridles for use with single joint pick-up elevators.

3.

Remove all thread protectors and drift casing (record drift diameter in report).

4.

Measure and number each joint as it is laid out, paint length and number on pipe body. (This must be done in conjunction with the Operator’s Drilling Supervisor.) It is recommended that joint number is painted approximately 3 - 5 ft from the pin end. This will assist the Driller to maintain a tally as the casing is run. The effective length of casing is required and not the total length (i.e. do not include pin threads which are made up). The measurement should be from the top of the box to the position on the pin where the box stops when the joint is fully madeup. This is on common oilfield connections as follows: •

Round-Thread: the plane of the vanish point on the pipe.

•

Buttress-Thread: base of triangle stamp on the pipe.

•

Extreme-Line: shoulder on pin end.

5.

Additional information is available in data books produced by specialist casing companies (e.g. Weatherford, Salvesen).

6.

Clean and inspect threads. Do not do this too early or corrosion will set in. There should be ample time available during logging/wiper trip operations.




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7.

It is standard practice for float collars and float shoes to be made up and threadlocked onshore. Check that this has been done. Handle these joints with due care and attention. Check these joints for any debris/rags. These joints will be thread locked so clean the threads thoroughly and “bag” same. Length of shoe track and number of connections to be thread-locked will be specified in Well Programme.

8.

Make up final casing tally after the casing has been drifted. Ensure that joints which did not drift are identified clearly.

9.

Check 350/500 ton spider (or flush mounted slips) and elevators. Dress same with slip inserts and guides required (Ref. Manufacturers Manuals) function test same and place on deck where they can be picked up quickly when needed.

10. Check temporary workstands for use with 350/500 ton equipment. 11. Inspect/test casing stabbing board. This can be done whilst logging/circulating, at a time when Driller considers it safe to do so. Ensure that Casing Service Hands do this along with AD/Derrickman and complete relevant reports. 12. Position casing tong power pack and test same. Rig up hydraulic hoses when safe to do so. Check back-up power unit if available. 13. Make up stop collars and centralizers as required by Operator’s Well Programme. Fit them to accessible joints on deck. Have rest ready for moving to rig floor at start of casing job. 14. Check CCTV for Driller observing casing stabber (where fitted). 15. Make-up casing hanger/seal assembly according to Well Programme and Wellhead Equipment Manufacturers Procedures. 16. Check plugs/darts required for cementing casing. Make-up crossovers/launching heads as required by Well Programme and Cementing Engineer. Drift landing string as required. Calculate landing string tally to give required stick-up above rotary table, and to prevent any surface landing string equipment (i.e. cement hose, side entry sub, cement head, tuggers) being caught up or struck by elevators links or elevators. 17. Complete the appropriate casing checklist (Ref. Enclosure No 3). 18. See individual well section checklists for more detailed information. 5.5.2

Running Casing - General Information 1.

Retrieve wear bushing, it is a good practice (if wear bushing retrieval tool has no jetting facility) to wash the wellhead during POOH prior to running casing to ensure proper engagement of retrieving tool.

2.

Hold tool box talk and fill in Casing Safety Checklist.




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3.

Rig up to run casing with side door elevators and manual slips, ensure that excess equipment is tidied away. Hold safety meeting with Drill Crew, contract Casing Crew and Deck Crew. Ensure that crew have chinstraps or safety lines fitted to hard hats where there is the possibility of a hat being lost in the casing at the rotary table.

4.

Pick up shoe joint using airwinch and deck crane (as per BHA Handling Procedures (Ref. Section 5.1). Ensure power tong ready for use before applying thread locking compound. Confirm make-up torque to be used with Casing Crew. It is easier to handle all joints to be threadlocked with airwinch and deckcrane into the side door elevators and then rig up single joint pick-up elevators once ready to run without locking connections.

5.

Check float equipment for proper operation. This can be done by filling up to the joint above the float collar, picking up on the string and checking that it drains (Shoe track joints should be tailed in with the crane).

6.

Attach and run stop Well Programme.

7.

Rig up single joint pick-up elevators and run casing by picking same up at V-Door. Dope the box threads with required lubricant at the V-Door (DO NOT dope pipe when set in rotary table).

8.

Use safety clamp/dog collar until shoe below wellhead and there is sufficient weight to ensure slips will hold casing securely. Be aware of the danger involved with using dog collar/safety clamp in conjunction with the flush mounted slips.

9.

Fill casing as it is run either through the DDM/top drive or dedicated fill up hose, check it is topped up every 5 joints if necessary.

collars,

centralizers

and

markers

as

per

10. Monitor returns in trip tank and keep trip sheet. Control running speed to minimise surge pressures and possible losses to formation. 11. Ensure that circulating swedges, crossover (water bushing) and stab-in valve are on rig floor before running casing. 12. Change over to 350 ton/500 ton spider, elevators and rig up temporary work stands before running casing into open hole. It may be necessary to change over before this if hookload is close to SWL of side door elevators. 13. Before setting casing slips, the string should be brought to a complete stop. The slips can be engaged and the load eased onto them. This will prevent shock loading of the string and damage such as crushing or gouging. Periodically check casing for signs of damage and replace dies if required. 14. Periodically check elevator and spider dies for accumulation of solids. Wire brush same if required. Check backs of slips are well lubricated (grease if nipples fitted, splash backs with oil if not). This will minimise the chances of slips “freezing” on the pipe.




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15. Maintain tally as casing is run. If it is necessary to lay out any joints (bad connections, pipe damage etc. notify Toolpusher and Operator’s representative) and try to replace the joints with joints of approximately the same length. NOTE:

Stop and hold a quick tool box talk prior to changing the routine from running casing to pulling casing, as this is when accidents can happen.

16. Carry out a count of joints remaining on deck before making up the hanger assembly. This should also be done before making up special equipment e.g. DV collar. 17. It is recommended when running hanger/seal assemblies with small annular clearances to open choke and kill lines on BOP to surface to minimise additional surge pressures. 18. Do not exceed 90% of DSC capacity when landing casing. If fitted, the active Heave Compensator may be used toProcedures adopted will depend on weather conditions at time of running casing and type of DSC in use assist in the landing of casing. 19. More specific information (Ref. Section 3). 5.5.3

is available

for

individual

well

sections

Cementing Casing •

Mix any pre-wash required by Well Programme whilst running casing. Flush surface lines as required.

•

Ensure manifolds, circulating lines are rigged up in advance of running casing - during logging/circulating operations. If possible, pressure test same to maximum anticipated pressure (Ref. Well Programme).

•

Ensure that low torque valve is rigged up on cement head for pressure testing surface lines before cementing.

•

Break circulation gently to avoid excessive pressures on formations and when full returns have been established then gradually increase the pump speed. It is recommended that at least the capacity of the casing and landing string is circulated.

•

Pressure test surface equipment against low torque valve with maximum anticipated pressure (Ref. Well Programme).

•

Ensure that there are always personnel posted in shaker house and pump room whilst circulating and cementing. Any changes to mud returns are to be reported to Driller immediately.




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•

It is essential when displacing cement to keep an accurate measurement of volumes. There will be the possibility of confusion arising due to differences between cement slurry weights and mud weights and the tendency for cement to “free-fall” in the casing. Later on during the operation mud return rate will seem to decrease but this does not mean that lost circulation is occurring.

•

When displacing cement and bumping plug, do not rely on stroke counters entirely, tally up volumes. Do not over displace cement by more than one half the volume between float collar and float shoe.

•

Once plug has been bumped, then increase the pressure to the casing test pressure required in the Well Programme. When releasing the pressure, line up to trip tank or cement unit tanks to monitor the volume bled back. If there is significant back flow, this indicates that the float valves are failing to hold. The same volume should be pumped back and the pressure held until the cement has thickened.

•

It is good practice to circulate and wash the wellhead area after releasing the running tool. (Care must be taken not to damage the hanger if the vessel is heaving, since this may hinder proper setting of the seal assembly.) Ensure that Mud Engineer checks the mud returns for cement contamination and measure or estimate volume of contaminated mud dumped. When pulling casing and laying out casing from the wellbore, the following procedure will apply:

• 5.5.4

A Tool Box Talk will be held by drill crews with casing crews, crane operators and roustabouts, with supervisors in attendance.

Pulling Casing •

Rig to be kept as level as practical.

•

Flush mounted slips must have pulling guides installed before casing operations proceed. (Small safety sling to be attached to flush mounted slips and pulling guides.)

•

If pitch or roll increases above 1.5 to 2°, the flush mounted slips will be removed and if casing string is heavy, the Varco 500 Ton Slips Are To Be Installed.

•

The 500 Ton Varco Slips should be removed and the side door elevators and manual slips installed, prior to pulling casing joints with centralisers installed.

•

The pick up elevators are to be closed and the safety pin installed free of casing.


Routine Drilling Operations •

5.6

5.6.1


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Casing joints with centralisers installed must be highlighted on the casing tally and extra care must be used when they are being pulled through the rotary table. Drillers to stop and verbally notify crews that remaining joints of casing to be pulled may have centralisers installed and extra caution to be taken.

Coring Operations •

The objective of coring is to obtain a representative formation sample for geological and/or reservoir analysis and evaluation.

•

Cores provide valuable information and the objective is to provide the maximum core recovery at the minimum operational cost. Cores will be taken upon request from the Clients Representative. His decision is subject to approval from onshore operations geologist who will discuss the coring program continuously with the actual Drilling Superintendent.

Preparations •

The Clients Representative, and Senior Toolpusher should ensure that all required coring equipment is on board.

•

Lay out, measure and caliper core barrel assembly before it is run in the hole. Ensure that fishing tools are on the rig for retrieving core barrel. (These are generally shipped as part of coring equipment.)

•

The hole must be free of any metal on bottom prior to running the core barrel. It is highly advisable to run a junk basket at least one bit run prior to going in with the coring assembly.

•

Prior to starting coring operations, but while drilling, the mud viscosity should be reduced to the minimum that will allow safe operations. Water loss should also be lowered to reduce filter cake build-up and thereby minimise possibilities of sticking. Lowering these properties will also reduce the circulating pressures.

•

Ensure that hole is clean and in good condition before running the core barrel. Wipe and if necessary ream any tight hole experienced when pulling out to run the core barrel.

•

Ensure that equipment is on the rig for handling and shipping any core retrieved. Position and hook up any cutting equipment used with glass fibre inner barrels.

•

Measure bit depth as accurately as possible when coming off bottom to run the core barrel. Measurement to be taken with zero weight on bit and tide correction to be applied where appropriate.




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Coring Equipment •

The most widely used coring tool is the conventional double tube core barrel with diamond or PDC core head. These core heads cut with a grinding action and thus reduce fracturing of the core. Non-fractured core is less likely to jam the core barrel, thus allowing for greater recovery. Damage to the diamonds or PDC's in a core head is usually the result of having junk in the hole, shock loading or burning caused by inadequate cooling. Therefore, extreme care should be used to insure that the following conditions exist: 1.

A clean hole.

2.

Excellent mud properties.

3.

Adequate circulation across the face of the bit.

•

The choice of core bit will depend on which type of formation is to be cored. Since it is possible to core faster in softer formations, larger diamonds are used in soft formation bits in order to gain a more significant penetration of the diamond into the formation. For hard formation core smaller diamonds are used.

•

Harder formation core bits are constructed using a round crown profile, whereas softer formation core bits utilise a more pointed crown profile to achieve maximum unit loading per diamond and, therefore, maximum penetration rate.

•

If the formation to be cored is a pure sand a PDC bit will be used. This will give the best penetration rate. If in doubt which core bit to start out with, a conventional diamond core bit 3 - 5 spc should be used.

•

For very unconsolidated formations a face discharge core bit might be used. Circulation volumes and pressure drops should be kept at a minimum during coring to minimise core deterioration and maximise recovery.

•

Core barrels are manufactured so that assemblies can be made up in single or multiple lengths. Core barrels can be assembled in 9.1 (30 ft), 18.3 (60 ft) or 27.4m (90 ft) lengths. If the recovery is poor or there are problems with core jamming a 9.1m (30 ft) section should be used. When a long sand section is to be cored and a 18.3m (60 ft) core barrel is filled without problems it should be considered to go in with 27.4m (90 ft) core barrel.

•

The conventional core barrel consists of an outer barrel which houses a free rotating, inner barrel. In order to obtain a representative sample, the inner barrel must not rotate with the outer barrel. This is accomplished by suspending the inner barrel on a swivel assembly which utilises a mud-lubricated anti-friction bearing. On top of the swivel assembly there will be a safety joint. The inner barrel will be either steel or glass fibre dependant of the formation to be cored.



5.6.4


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Picking Up and Running Core Barrel •

Pick up core barrel as guided by Coring Engineer and using BHA Handling Procedures where applicable (Ref. Section 5.1). Ensure that all inner and outer barrel connections are made up to torque required (ensure tongs are correctly placed to avoid damage to threads).

•

Take care with PDC/diamond coreheads to avoid striking sides of rotary bushings etc. Stand same on wooden or fibrous mats and not the steel deck.

•

It is good practice to run a pipe wiper beneath the rotary table when running in the hole with PDC/diamond coreheads.

•

Run in the hole carefully to avoid striking ledges/bridges etc. which may damage the corehead. Use the DSC to pass the BOP. If it is necessary to wash and ream any tight sections ensure that Coring Engineer is on the rig floor to supervise the operation.

•

Break circulation and tag bottom gently. Measure in and confirm depth with appropriate tide correction.

•

If there have been high trip gas readings on previous trips then consider circulating bottoms-up before dropping the ball.

•

Whilst circulating, after tagging bottom, determine space out required to ensure maximum core is cut before it is necessary to make a connection (pick up a pup joint if required). There is more chance that the barrel will become jammed at a connection.

•

Pull pipe wiper from beneath rotary table and add any pup joints required for space out. The ball can be dropped into the string at this point.

•

Once the ball has seated - indicated by increased standpipe pressure, then take SCRs (Ref. Well Control Manual WCO 200). Note, off-bottom pressure at circulating rate to be used whilst cutting core.

Cutting Core Before the coring operation is started, careful consideration should be given to the following three variables: 1.

Circulation rate. Bit manufacturers provide recommended circulating rates based on the number and size of water courses in the bit and also on the weight of the drilling fluid. These recommended circulation rates should be followed.

2.

The range of rotary speeds used in a diamond/PDC coring is relatively narrow. Most successful coring is performed with rotary speeds of 50 -100 RPM. The rate of penetration increases with rotary speed. However, practice has shown that the increase is less pronounced above 100 RPM and the danger to the bit is increased.




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Bit Weight. Sufficient drill collars should be run to give the anticipated weight on bit and also keep the drill pipe in tension. Bit weights of 40 -80 kN (9,000 lbs - 18,000 lbs) will usually ensure penetration in hard sands. Bit weight should be varied while drilling, maintaining a close watch on the pump pressure to determine the optimum bit weight for a specific formation.

When coring operations are started, it is a good practice to cut the first 0.5m (1.5 ft) with only 8 to 10 kN (1,800 - 2,250 lbs) and also with reduced rotary speed. Allowing the weight to drift off will produce jarring on bottom and can result in severe damage to the core head and coring assembly. When the bit has established a pattern and the core is entering the inner barrel, the pump pressure will increase. This increase is dependent upon water-course area and circulation rate and is a result of the pressure drop across the bit face. This final pressure reading, obtained after the bit has started drilling, must be kept in mind throughout the coring operation. Any change in pump pressure indicates that something abnormal is occurring and the cause must be determined. The pump strokes should be checked to ensure that the circulation rate has not varied. Changes in pump pressure can indicate several general core barrel problems, as follows: 1.

If the pressure increases and the circulation rate is correct, raise the bit off bottom and record the pressure. If the pressure drops but then returns immediately to the abnormally high pressure when the bit is placed on bottom, then most probably the bit has failed. A destroyed ring of diamonds will allow the formation to cut into the bit matrix, thus restricting the water course and causing the pressure to increase. When this situation occurs, pull the bit.

2.

If the pressure remains constant when the bit is pulled off bottom, most probably the bit or the circulating system is partially plugged. This condition may correct itself with continued circulation. Continued high pressure may also be an indication of swivel failure resulting in the lowering of the inner barrel and closing of the fluid passage between the bit and the bottom of the inner barrel. As long as the pressure is reasonable and the circulation rate acceptable, continue coring.

3.

A pressure decrease may be due to a wedged core which will tend to hold the bit off bottom. In this case, the decrease in pump pressure will be accompanied by a reduced penetration rate and lower torque. If this condition continues after raising and lowering the bit, pull the bit out of the hole.

4.

When the pump pressure fluctuates continuously and the penetration rate is erratic, it is possible that alternate wedging and crushing of the core is occurring. The coring assembly should be pulled to avoid loss of core recovery.



5.6.5


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•

When making a connection, the rotary table should be stopped and the core assembly picked up off bottom very slowly. The core will usually break off easily, however, observe the weight indicator closely. A noticeable jump on the weight indicator will occur when the core breaks. If problems occur in breaking the core, pull 60 -100 kN (13,500 lbs 22,500 lbs), set the brake and slowly rock the rotary until the core breaks.

•

When the core is broken, the string should be raised approximately 5m (16.5 ft) and then slowly lowered to within 0.3m (1 ft) off bottom while feeling for any core that may have been left on bottom. If a piece of core has been left in the hole, it can sometimes be worked back into the barrel. Light bit weight and very slow rotation of the rotary is used in this operation.

•

After making the connection, go back to bottom slowly and rotate 50 RPM until the bit is again cutting and the new section of core is entering the inner barrel.

•

A full core barrel will result in a pressure decrease and loss of ROP. Break the core and check for lost core using same procedures as at connections. Check depth measurements and correct for tide as required.

•

Further coring might have to be stopped if tight hole, heave etc. create problems.

•

Diamond/PDC coring is an exact operation and success is aided by careful attention to all surface indications. Detailed examination of the core bit, core and core barrel after the assembly is on the surface can provide valuable information for future core runs.

Pulling Core Barrel And Slipping Core •

Circulate bottoms up before starting POOH. If the penetration rate and gas readings have been extremely low consider POOH without circulating bottoms up.

•

Never rotate core barrels on trips. Set slips gently while POOH to avoid losing core from barrels.

•

Take extra care when pulling out of the hole as there will be increased chances of swabbing.

•

Swabbing because of rig heave might be a problem when coring operations are carried out. Therefore great care should be taken when tripping out of the hole with a core bit.

•

Ensure that string is set into/pulled out of the slips with extra care to avoid shaking and losing the core, avoid rotating the string whilst breaking connections.


Routine Drilling Operations •


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Ensure that required number of boxes for handling the core are prepared for lifting to floor in plenty of time. Slip core as directed by Coring Engineer, make sure that: 1.

Due to the light loads involved whilst handling the inner barrel, that the air line from the automatic elevators is disconnected, or use manual elevators for this operation.

2.

Driller can see Coring Engineer and core barrel clearly.

3.

Clear and distinct signals are used by Coring Engineer and that no other person signals the Driller.

4.

Drill floor is clear and only essential personnel are allowed access.

5.

For the first core to surface in each hole section, the drill floor crew should don BA sets at the start of pulling drill collars through the rotary table. Each connection broken in the drill collars, especially just above the core barrel and during core retrieval, must be checked for H2S with a suitable gas detector. BA should continue to be used until the core has been lowered from the rig floor. Depending on the results of the first core, a decision will be made at the rig site whether BA sets continue to be donned for subsequent core retrieval.

6.

The barrel is raised slowly to try and use natural breaks to separate the core.

7.

The barrel is not raised too far, this might let too much core fall out.

8.

No hands are placed beneath the core. Use Geologists hammer, or a pipe wrench etc. to remove small pieces of core.

9.

The barrel is kept hanging as near vertical as possible. Check for H 2S.

10. Lower the bottom of the barrel to the floor. 11. Fit core catcher, break off the core catcher assembly and release the core. Raise the barrel slowly until a natural break in the core appears. Activate the core catcher, remove the pieces of core, lower the barrel back down to the floor and repeat until the barrel is empty (sometimes signified by the appearance of a lightweight rabbit). 12. Ensure that the barrel is not raised to an unsafe height which might let too much core fall out. 13. If using glass fibre inner barrel, one section at a time will be broken down and laid out on the catwalk. The glass fibre barrel with the core will then be cut on deck.




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Laying Out Core Barrel Lay out core barrel as directed by Coring Engineer using BHA handling procedures where applicable (Ref. Section 5.1).

5.7

Fishing Operations

5.7.1

General The word “fish” is used to describe any object in the hole that cannot be pulled at will. Fishing tools and operations are used to remove these objects from the well. Failure to recover the fish can lead to the well requiring redrilling, sidetracking or even abandonment with the associated costs and losses involved. It is of great importance to consider the possible causes of fishing jobs and take every possible precaution to prevent them.

5.7.2

Causes Of Fishing Jobs General Most fishing operations result due to hole conditions, equipment failure, or improper operating practices. Sticking the drill string - this can lead to the string failing under the additional stresses imposed to attempt to free it. Alternatively if the string cannot be freed then it is released above the stuck point (back-off Ref. Section 5.4). It is then necessary to fish the portion left in the hole. Differential Pressure Sticking Differential pressure sticking results from the drill string being imbedded in the mud filter cake and the hydrostatic pressure from the mud column being greater than the formation pressure (Ref. Section 5.3 Drilling Problems) for more detailed information. Junk Left In Hole This can be due to bit failures, leaving cones, bearings, teeth etc. at the bottom of the hole and a fishing operation is required to recover these before normal drilling operations are resumed. Inadequate Hole Cleaning 1.

Excess fill after tripping.

2.

Small amounts of cuttings over the shaker.

3.

High torque and variation in RPM.

4.

Tight hole on connections.

5. 6.

Decrease in pulling loads when circulating. High pressures required to break circulation.




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A steady increase in pressure while drilling.

If tight hole is experienced, never pull too hard into the tight spot. Stop and go down again and work the pipe through the section. Do not pull more than can be slacked off again going down. Drill String Failure Mechanical failures of the drill string are a primary cause of fishing jobs. This type of fishing operation is usually caused by one of the following reasons: 1.

Improper care and/or maintenance of the drill string.

2.

Improper make-up torque.

3.

Improper drilling practices.

Improper design of the drill string drilling studies indicate that more than 75% of all fishing operations result from poor hole conditions. Annular velocity, mud density, viscosity and gel strength are the main factors considered when cuttings are not being carried out of the hole. Fishing jobs that result from drill string failure should be analysed and operational practices changed in an attempt to avoid reoccurrence. 5.7.3

Preventing Fishing Jobs In order to monitor trends the Driller should fill in an hourly parameter sheet whilst drilling, this will allow early detection of impending problems (Ref. Enclosure No 4). The initial procedures, when a drill string sticks, are to slowly work the string and circulate in an attempt to free the string. Drillers should never pull more than the sum total of the string/BHA + normal hole drag or set down more weight than the string down weight less BHA weight (without first notifying the Toolpusher and until the Client's Representative is on the floor). This overpull should not be more than 75% of the designed maximum overpull. The primary consideration is to never exceed the yield strength of the drill pipe being used. After the string is stuck, the pipe should be worked up and down with a small amount of applied torque. If drilling jars are included in the string, they should be immediately tripped. This will normally determine if the string is free down to the jar and may free the stuck string. If the string becomes stuck while being hoisted, attempt to free by bumping downwards. When the string sticks and the hole cannot be circulated, an attempt will be made to determine where the flow is blocked. Generally, if the pump pressure locks without bleed off, the drill string or bit is plugged. If there is a slight bleed off in drill pipe pressure, there is a possibility that pressure is being applied to the formation. In either case, the applied pressure should not exceed the fracture gradient of the open hole. The string should be worked within a safe pressure range in an attempt to establish circulation.




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If annulus is partly of fully blocked, max. pump pressure without breaking down the formation should be used while pulling on the pipe to get out of the hole. Prior to pulling on the stuck string the weight indicator system must be checked to ensure its operational capability. Proper use of good drilling practices will minimise drill string failures (Ref. Section 5.5 (Drill String) in DOP 206 Maintenance). Vigilance in checking connections, pipe body condition etc. during trips might prevent the piece of equipment being rerun. It is better to lay any equipment out that may look doubtful than to take a chance and run it in the hole where it might fail. Be alert to changing hole conditions (Ref. Section 5.1 Drilling Problems) in DOP 204 Drilling Problems) monitor parameters whilst drilling to determine optimum time to pull and change the bit before failure occurs. Take appropriate precautions to prevent items being dropped in the hole through the use of hole covers, pipe wipers etc. 5.7.4

Fishing Job Preparations 1.

Ensure that sufficient mud and mud materials are available. Check that sufficient volumes of pipe freeing chemicals are on board for spotting fluid to free differential stuck pipe. Check that all required fishing tools are on the rig.

2.

Measure calliper and sketch all fishing tools prior to running into the hole.

3.

Check the weight indicator system to ensure its operational capability.

4.

Make sure that all measurements are taken before drilling tools are run in the hole for the first time, (Ref. Section 5.1). It is important to check these measurements occasionally to monitor any wear that may be occurring downhole.

5.

Make sure that there is fishing equipment suitable on board the rig for the most common tool and hole sizes. Cross check this with measurements taken in (2).

6.

Spot check measurements on hevi-wate and drill pipe to monitor for wear. In high angle deviated wells, there can be high wear of tool joints, hard banding etc. Any equipment that has become undergauge should be removed from service for repair.

7.

Analyse circumstances leading to the fishing job and select the most suitable tool for the job. Points to consider: 8.

What was the operation when the problem occurred?

9.

How is the string stuck? - Is the string differentially stuck, stuck with hole cuttings, stuck from a cave-in, stuck from object wedging against the string, key seating? 10. Where is the free point?




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11. What do the drilling charts indicate? 12. What are the hole characteristics? 13. Have similar failures occurred or almost occurred prior to the existing situation? 14. Hole condition, clearances, deviation, is there a need to circulate etc.? 15. If there has been a back-off, need to check make-up torque on connections whilst running fishing string? 16. Physical appearance of the fish based on failed portion retrieved? 17. Is there a potential well control problem? 18. Procedures required for particular tools. 19. Methods to release fishing tool if fish cannot be freed. 5.7.5

Common Fishing Tools These shall be considered in a general way, more detailed procedures for their operation and capacities may be obtained from their Manufacturers Manuals. 1.

Impression Blocks - These are run if there is some doubt as to the condition of the top of the fish.

2.

Milling Tools - These are run if the top of the fish has been badly damaged, burred or split. It is then necessary to mill down to a better section of the fish.

3.

Overshots - These are fishing tools which grip the fish externally. They have several useful features: 1)

Right hand rotation is used to both engage and disengage the fish.

2)

They contain a packer which seals around the fish, enabling drilling fluid to be pumped through the fish. This helps to clean up around and loosen the fish.

3)

Spears - These grip the fish internally when there are insufficient hole clearances to run an overshot, e.g. to retrieve casing. They can be released easily.

4)

Taps And Dies - The first and simplest fishing tools developed. They cut threads onto the fish to enable the fish to be gripped and pulled. They are inexpensive and require virtually no maintenance. Their main disadvantage is that they cannot be released except by breaking the tool or stripping the threads.


Routine Drilling Operations 5)

5.7.6


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Junk Baskets - These come in various forms and are used to retrieve small objects such as bit cones, dropped objects etc. Most common types are: 6)

Poor boy - tube with fingers cut in the lower end, incapable of removing objects embedded in hard formations.

7)

Reverse circulating and core-type. These cut a core from the formation using shoe with hardfaced teeth and then retain it with folding fingers. Reverse circulating action is created by dropping a ball down the string and seating in position on the valve seat. Flow is then diverted to create a reverse circulating action to carry junk into the tool.

Miscellaneous Tools 1.

Jars and accelerators - run to deliver blows to knock the fish free.

2.

Bumper subs can be run to enable blows to be delivered to knock the fish free or to release the overshot. Primarily used for downhole compensation in place of surface compensator.

3.

Junk subs. Run with mills and bits to collect milled pieces and small pieces of junk.

4.

Fishing magnets. Powerful, permanent magnets with passageways for drilling fluid to be circulated through them. The hole is cleaned and the junk picked up and held by the magnet.

5.

Washpipe. Run with rotary shoes to cut a clearance between the fish and the sides of the hole to loosen it.

6.

Cutters. External cutters are a last resort when a stuck drill pipe string can only be removed by cutting it into manageable lengths. Run on washpipe in place of the rotary shoe. Internal cutters are used to cut and pull casing. The use of internal explosive cutters has almost completely replaced inside cutting of drill pipe and tubing.

7.

Safety joints. These allow quick release from fishing and washover strings should they become stuck, leaving a minimum of pipe in the hole.

8.

Wireline grapples. These are used to fish broken wireline from the hole.




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Summary It is important to approach a fishing problem in a thoughtful and controlled manner. Time spent thinking about possible problems that could be encountered will be time well spent. A hasty, ill conceived approach may make an already bad situation worse.

5.8 Well Testing Operations 5.9 Preparations General Preparations The following preparations should be carried out on the rig in advance of the test: 1.

The BOP stack should be tested.

2.

An adequate volume of properly weighted mud should be available.

3.

The OIM should schedule BOP, fire, and H2S drill prior to the testing.

4.

Fire hoses should be laid out in the vicinity of the burners and surface testing equipment. Fire extinguishers should be placed close to the surface equipment.

5.

Spare arrestor, remote shut down system, over-revving system and diesel leak automatic shut down system should be installed on the mobile air compressor, if used.

6.

The OIM, Clients Representative and Testing Engineer should hold a pre-test meeting attended by all parties concerned with the test to ensure that the expected course of events, responsibilities and contingency measures are fully understood.

7.

The OIM should schedule a safety meeting with the whole crew prior to the test. All personnel should be made aware of test expectations and restrictions imposed during testing, i.e. welding radio use, helicopters, use of cranes over well test area etc.

8.

Hazardous areas should be clearly marked off.

9.

All required H2S equipment is to be onboard and tested.

10. Dispersion chemicals should be stored on standby boat. 11. The standby boat and helicopter base should be advised that the test is about to commence. 12. The OIM and Clients Representative should notify the RCC by telex that the test is commencing. A copy of this telex is to be sent to Operator’s office.




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Preparations In Advance Of The Test 1.

All surface lines, the separator and flow-tank should be flushed with water.

2.

The cooling sprays on the burners and rig should be checked and any plugged jets cleared.

3.

Surface lines, separator with its relief valve, gas heater, choke manifold, lubricator valve, subsea test tree and surface test tree should be pressure tested. Relief valve will not have to be lifted if calibrated on shore just prior to job and witnessed by Certifying Authorities.

4.

The wireline lubricator and its assembly on the surface test tree should be checked and pressure tested.

5.

The activation of the surface test tree safety valve, subsea test tree valves and lubricator valve should be checked.

6.

The burner ignition system should be checked.

7.

The separator flowmeter should be calibrated by pumping water through them into the flowtank. The separator controls to be checked.

8.

The lengths, OD, ID and threads of all downhole test tools should be checked and a tally of the test string made.

9.

The packer should be checked to ensure that it is correctly made up for the size and weight of casing in which it is to be set.

10. The actuation of downhole valves should be checked. 11. The dimensions of the subsea test tree and slick joint should be checked to ensure that the tree will locate correctly in the wellhead and BOP. 12. Gauges, hangers and gauge dimensions should be checked to ensure that they will locate correctly in the carriers. 13. All electrical lights, outlets, switches shall be checked in the general area of the well test units. • •

•

Check that well test equipment layout conforms to plan submitted and approved by certifying authority. Lay out, measure and drift testing string (Ref. Test Programme and Well Test Supervisor on board for items/procedures required). Tally same and prepare running order. Check all handling equipment required: elevators, slips, safety clamps, lift subs, crossovers etc. Ensure fishing equipment available for fishing test tools and tubing used. Ensure that correct crossovers are available on the rig floor to enable stab-in valve to be used for well control.



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•

Well test equipment to be tested as per Well Test Programme and Well Testing Company Procedures to satisfy requirements of Certifying Authority. All pressure testing to be carried out as per the Company pressure testing safety procedures. Test all remote shutdown systems ensure that responsible personnel are briefed on operation of these.

•

Ensure well test area deluge systems (where fitted) have been tested. Check all remote control stations (where fitted). Rig up and test all rigside cooling systems for use during flaring of hydrocarbons. Ensure that hoses are spotted where additional cooling might be required.

•

5.8.2


•

Check that subsea test tree and slick joint dimensions are correct for wellhead/BOP space-out. This may be confirmed using a “Dummy Run” (Ref. Well Test Programme).

•

Meeting to be held with OIM, Senior Toolpusher, Operator’s Drilling Supervisor, Well Test Supervisor and all parties concerned with the testing to discuss, draft and implement any specific procedures required.

•

In areas where there may be H 2S at surface during flow periods, then ensure that equipment and contingency procedure are ready. Carry out training and drills to ensure proper response by emergency teams and non essential personnel mustering.

Running D.S.T. Equipment 1.

Hold a crew safety brief.

2.

Procedures will be given in Specific Well Test Programme.

3.

Make-up of well test tools will be supervised by their Service Engineers. Ensure slips are set and hole covered when installing downhole gauges.

4.

Handle drill collars etc. as per BHA procedures (Ref. Section 5.1).

5.

Monitor well on trip tank and keep trip sheet.

6.

Fill test string with required cushion and pressure test string at intervals specified in the Well Test Programme. Observe Pressure Testing Safety Procedures. Control running in speeds when running packers and be alert for these tools setting inadvertently during RIH. In order to prevent pressure surges inside the string which may affect the tools, the string should be brought to rest gradually before setting the slips. It is also important to ensure that the string does not rotate whilst making up connections.

7.

8.

Handle long test tools, subsea test tree and surface tree joint as per BHA Procedures (Ref. Section 5.1).




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9.

Tally string as it is run, check joints left on deck or in derrick before picking up/running subsea test tree. 10. Ensure that “YC” (slip type) elevators engage the tubing in the correct location. These can grip the tubing in the wrong position (particularly when picking up from mousehole) and then allow the tubing to slip down once it has swung to vertical while Floorman is removing pin end protector. 11. Well test/well kill. 12. Ensure that installation cooling is running before flaring hydrocarbons. Check that all equipment is protected from water damage (where applicable) and close off any intakes or exhausts to prevent water ingress. 13. During flaring operations, carry out regular inspections of likely “Hot Spots” and apply additional cooling where it may be required, e.g. rig columns, inside box girders, riser tensioners and DDM hydraulic pipework on derrick leg. 14. Ensure that the well is closed in with 2 barriers when rigging up wireline equipment (BOPs and lubricator). Pressure test same as per Well Test Programme. Use glycol/water mix for flushing surface equipment to minimise problems due to hydrates. 15. Observe safe working practices for installing/removing wireline equipment.

manriding

winches

when

16. During well test, check mud/brine kill fluid in pits to ensure proper weight maintained and that there is adequate volume to kill the well. 17. Hold meeting prior to well kill to verify procedures to be used. Ensure that good communications are established between rig floor, test choke manifold, separator etc. 18. Kill well as per Well Test Programme. Ensure surface lines and equipment completely flushed to burners if test programme completed. 5.8.3

Pulling DST String 1.

Proceed as per Well Test Programme. Ensure that well is flow checked after unseating/pulling out of packer. Driller to be aware of position of tools across BOPs.

2.

Lay out surface tree as per BHA procedures (Ref. Section 5.1).

3.

If more than one test to be carried out, then DST string will probably be racked in derrick. Ensure that rig stability criteria have been considered.

4.

Monitor well on trip tank and keep trip sSheet. Inform Toolpusher and Operator’s Drilling Supervisor immediately if well taking incorrect volumes.



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Take care when breaking DST downhole tools as sections may contain fluids at bottom hole pressures, ensure that Service Engineers are on the rig floor to supervise these operations. Ensure slips are set and hole covered when removing downhole gauges.

5.9

Well Completion/Workover Operations

5.9.1

Preparations

5.9.2


•

Lay out tubing, number and measure same and make up tally. Remove protectors, clean and inspect threads (this will usually be done by Inspection Engineer).Drift tubing.

•

Lay out, measure and prepare completion tools.

•

Position and hook up HPUs and hose reels required for control of xmas trees and wireline BOPS.

•

Flush surface manifolds, lines, mud pits etc. as required to handle completion fluids e.g. filter treated sea water, weighted brines etc. Install and hook-up filtration equipment as required by completion programme.

•

Check all handling equipment required: 1.

Elevators, slips, lift subs, crossovers, safety clamps etc. Ensure fishing equipment available for fishing completion tools and tubing in use. Ensure that crossovers are available on the rig floor to enable stab-in valve to be used for well control.

2.

Check that there are adequate supplies of protective work gear, barrier creams etc. for use with corrosive completion fluids (R. ref. chemical data sheets supplied).

Running Completions •

Run completion as per completion programme (Ref. Operator’s Drilling and Completion Supervisors).

•

Monitor well on trip tank and keep trip sheet.

•

Handle long completion assemblies as per BHA handling procedures.

•

Use safety clamp with slick tools and until sufficient string weight is present to set slips securely.

•

Ensure that “YC” (slip type) elevators engage on tubing in proper location. These may grip tubing in the wrong position (particularly when picking up from mousehole) and then allow the tubing joint to slip down once it has swung into a vertical position while Floorman is removing pin protector.



5.9.3

5.9.4


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•

Observe handling procedures for special tubing strings e.g. tubing with high chrome content as per Well Completion Programme.

•

Pressure test completion as per Well Completion Programme. Observe the Company Pressure Testing Safety Procedures.

•

Control running speed to prevent inadvertent setting of packers.

Commissioning And Wireline Work 1.

Observe safety procedures required when pulling BOPs and installing xmas tree e.g. moving rig off location etc. (Ref. Well Completion Programme/Operators Procedures).

2.

Test tubing hanger valves, downhole safety valve(s) as per Well Completion Programme. Observe the Company pressure testing procedures.

3.

Observe the Company Safe Working with Man Riding Winch Procedures when installing/removing wireline BOPs and lubricator on surface flowtree.

4.

Ensure surface equipment, wireline riser, wireline lubricator and BOPs are flushed to remove hydrocarbons before breaking and rigging down equipment.

5.

Restrict Crane Operations during wireline work to avoid collision between load and wireline rigged up in V-Door. Any lifts required close to wireline should only be carried out following discussion between:

6.

Senior Toolpusher, Operator’s Supervisors (Drilling and Completion) Wireline Engineer and Crane Operator. This type of lift should only be done when wireline tools are out of the hole and the well is secure.

7.

Ensure that 2 barriers are closed and pressure bled off before opening wireline lubricator to change out tools.

Coil Tubing/Acidising Operations Hold meeting between Senior Toolpusher, OIM, Operator’s Drilling Supervisor, Coil Tubing Company Supervisor(s) to discuss operations and equipment involved. If possible get Coil Tubing Supervisor(s) onboard rig before equipment arrives and then equipment can be spotted straight into position as it comes aboard from the supply boat. Items to consider: 1.

Clearance for bringing equipment through V-Door.

2.

Positioning of tubing reel and injector head to enable tubing to be installed before moving injector head to floor.

3.

Rig up and procedures to use when moving injector head complete with tubing fitted to rig floor and then into working position on tubing BOPs and surface flowtree.




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4.

Positioning of pumps, tanks etc. for allowable deckload (Ref. Installations Operations Manual).

5.

Isolating areas around acid tanks etc. and maintaining escape routes.

6.

Ensure that all surface lines for pumping acid, nitrogen etc. are fitted with safety wires/chains. Observe pressure testing procedures when testing same.

7.

Restrict crane operations when coil tubing in use to avoid collision between load and tubing. Urgent lifts close to the tubing should only be carried out following discussion between: Senior Toolpusher, Operator’s Drilling and Stimulation Supervisors, Coil Tubing Supervisor and Crane Operator. This type of operation should only be carried out when coil tubing is out of the hole and NOT under pressure.

8.

Observe Safe Working with Man Riding Winch Procedures when installing/removing Tubing BOPs etc. on surface flowtree.

9.

Hold safety meeting with Senior Toolpusher, Operator’s Supervisor(s), Drill Crew, Deck Crew and Stimulation Engineers before acidising operations. Ensure that contingency plans prepared for acid spill/leak at high pressure lines and check that communication systems are in place for rapid shutdown of pumping operations. It would be beneficial to have plasticised sheet posted in Dog House for valve status to be updated by Driller, especially for workovers.

10. During acidising operations, rope off substructure area and keep personnel clear in case of acid spillage from rig floor. 11. Lay out and test water hoses in all areas where acids are being pumped. Check that personnel assigned to any standby/clean up duty have appropriate personal protection, acid resistant chemical suits, rubber boots, gloves and face visors. 12. Check that any medical kits for treatment of acid burns are ready and available close to the operation.

5.10

Well Suspension Or Abandonment

5.10.1

Preparations •

Ensure that sufficient cement additives to complete the abandonment programme are on-board. Check that all necessary equipment and tools are sent out.

•

Ensure that the wireline companies equipment is compatible with mechanical plugs to be used. Check that all cutting/abandonment tools are according to service companies specifications. Check crossovers to contractors equipment.

• 5.10.2

General Procedures




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Open Hole/Cased Hole Plugging •

Open hole plugs longer than 300m (990 ft) should not be set in one step.

•

Run in hole with open ended drill pipe (OEDP) to depth of bottom of the plug to be set.

•

Circulate and condition mud until in balance.

•

Set balanced cement plug to fill length of hole as required in abandonment programme. Displace cement with mud.

•

Pull OEDP out of cement plug slowly. Do not rotate pipe. Reverse circulate drill pipe clear of cement, identify and dump any cement contamination.

•

If open hole below the deepest casing, the top of the plug across the casing shoe shall be tagged, load tested and pressure tested to 70 bar (1,000 psi) differential pressure.

Installation Of Mechanical Plugs Mechanical plugs will be used when squeezing of perforations and at casing shoe when the condition of the formation makes cementing across the shoe difficult, these will normally be set on wireline. Pressure test plug against shear rams once wireline is out of the hole. Cement Squeezing 1.

Perforate zone to be squeezed.

2.

Run cement retainer and set above perforations.

3.

Run in hole with cement stinger on drill pipe and sting into retainer. Have enough weight (HWDP) to prevent pumping stinger out of packer.

4.

Pressure test surface lines to maximum expected pressure. Close BOP (spherical) and pressure up annulus to 500 psi (34.5 bar) to check for packer leaks.

5.

Carry out injectivity test.

6.

Bleed off annulus pressure and strip out of the retainer, mix cement, and displace cement to stinger. (Hold sufficient back pressure to prevent the cement u-tubing out of the pipe.)

7.

Sting back in, holding annulus pressure and squeeze according to abandonment programme.

8.

After completion of the squeeze, bleed off and pull out of the retainer and dump the remaining cement on top of the retainer.

9.

Pull out of the cement and reverse circulate, identify and dump any cement contamination.





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Perforating For Squeezing/Checking For Pressure

5.10.3

1. 2.

Perforating to be carried out according to the abandonment programme. Run 5" DP through wellhead.

3.

Close upper pipe ram above and middle pipe ram below a tool joint.

4.

Install pump in sub and wireline BOP on top of drillpipe.

5.

Install a line from standpipe manifold to the pump in sub.

6.

Run perforating gun to required depth.

7.

Pressure test the system to maximum expected pressure.

8.

If gas should be encountered when perforating, circulate gas out through choke manifold.

Abandonment Temporary Abandonment In the case requirements.

of

temporary

abandonment

there

are

certain

additional

1.

A mechanical bridge plug shall be placed in the smallest string of casing which extends to the ocean floor, at a depth of 200 - 300m (660 ft - 985 ft) below the ocean floor.

2.

A corrosion cap shall be placed on the wellhead.

3.

Set cement and mechanical plugs as per programme.

4.

Pull BOPs as per Company Procedures.

5.

Cut/retrieve guidelines.

Permanent Abandonment Casing Cutting And Retrieving •

Cutting and retrieving of casings shall not be done unless a check for pressure behind the casing has been carried out. When a well is abandoned, parts of the casing string and other installations extending above the seabed will be removed. The casings must be cut at least 5m (17 ft) below the seabed. The cutting operation will be executed primarily using mechanical cutting tool. The 9-5/8" and 13-3/8" casing are cut and retrieved before retrieving the BOP and riser.

•

The 20" and 30" casing are cut and retrieved after retrieving the BOP and riser.




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Mechanical Cutting 1. 2.

Run in hole with the casing cutter to the desired depth. Land out marine swivel in w/head with 10,000 lbs. Let the cutter knives expand by applying pump pressure.

3.

Rotate the cutting string.

4.

Watch for signals indicating that the knives have cut through the casing.

5.

Pull out of the hole with the cutting assembly.

6.

Run in the hole with casing spear and retrieve the casing string.

7.

The 20" and 30" casing can be cut in one run and retrieved along with the PGB by using the 20" casing spear. Winch operators should be positioned as required to retrieve guidelines.

Explosive Cutting PRECAUTIONS WHEN USING EXPLOSIVES FOR CASING CUTTING AND WELLHEAD RECOVERY. •

The explosive cutting container must be completely filled each time to give an instantaneous explosion and, therefore, it is difficult to vary the charge beyond the specified value i.e. 27 lbs and 35 lbs equivalent TNT. Vendors provide reasonably comprehensive data file and graphs showing measured pressures taken during field operations. The graphs show free field overpressure at the hull due to the explosion/against safe stand-off.

•

Stena Drilling Limited limits the free field pressure (i.e. dynamic loading) on the hull due to explosion to 50 psi. By using this figure and consulting the vendors data charts, the required safe stand-off can be obtained.

•

For example, using the smallest effective charge which is 27 lbs, the safe stand-off is 233 ft, and when the transit draft (i.e. fully deballasted condition) is added, a minimum water depth at which explosive cutters can be used is obtained.

NOTE: •

Below this water depth explosive cutting on location is not approved.

The charge can vary up to a maximum equivalent of 50 lbs of TNT. In all cases the running string has ballast/shock attenuators that are run into the wellhead above the charge. It is beneficial to size these ballast chambers as close to the minimum casing dimensions as possible, thus reducing the pulse energy transmitting upwards. Below are listed various points that must be considered and adhered to in any explosive cutting operation.




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1.

The safe stand-off is the distance in feet from the mud line to the bottom of the hull pontoon. When calculating the safe stand-off, the draft of the rig should be subtracted from the water depth.

2.

The explosive cuttings charge must be placed at least 15 ft, and as much as 20 ft below the mud line, to reduce as much as possible the pressure on the hull. The factors affecting this pressure on the hull are: 3.

Depth of charge in the wellhead.

4.

The type of granular material (mud, gravel etc.) surrounding the wellhead.

5.

The number of strings of casing (the more strings present the lower the pressure).

6.

Presence of inversion layers (temperature differentials).

7.

The salinity of the water.

8.

The mud line is the seabed, but in this case it must be taken as the point at which the mud completely surrounds the wellhead/casing. In cases where cratering has occurred or the sea bed is eroded away, the mud line is considered to be at the wellhead.

9.

The heave of the rig must be considered and allowance made to ensure that the locating collar or wellhead cover/shock attenuator is not lifted off, simultaneously lifting the charge higher in the wellhead.

10. The OIM and the Senior Toolpusher should themselves check all measurements when running the charge into the wellhead, to ensure that the charge is set off 15 - 20 ft below the mud line as defined in point 3. 11. In all but really deep water and when there is any doubt about mud dampening etc. the rig should be de-ballasted to reduce the hydrostatic pressure on the hull, simultaneously increasing the stand-off. The water depth and draft constraints are as follows: Charge (equiv TNT)

Min Water Depth Draft (ft) (ft)

Safe Stand off (ft)

27 lbs

255

22

233

35 lbs

287

22

265




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NOTE: 1.

For water depths up to 500 ft the draft must be as near as possible to 22 ft.

2.

For water depths greater than 500 ft the explosive cutting operation may be performed at any draft.

3.

When considering peak pressure, the free field overpressure must not exceed 50 psi. The safe stand-off for the various values of charges can then be read from the graph. Should circumstances arise that are not covered by the above guidance notes, the shore base should be consulted. In any event, the Rig Manager must be contacted as soon as it is known that explosive cutting is planned. Retrieving guide bases using explosives only to be performed when mechanical cutting has failed or where hard formations have caused problems with retrieval after mechanical cutting. If cutting by explosives, consider the effects of underwater explosion on rig structure and equipment such as hydrophones etc.

Sea Bed Inspection Before retrieving the wellhead and the guide-base the area around the location will be visually inspected using the ROV. When the wellhead equipment is secured in the moonpool the ROV will make a final inspection of the sea bed around the location. This inspection shall be recorded on video tape. If sea floor conditions permit the area around the wellhead location will be overtrawled with a special trawl. If trawling is not carried out, a side scan sonar shall be run to locate the position of possible lost objects. Drawings A detailed drawing should be prepared showing all cement and mechanical plugs placed in the hole, and in addition where a temporary abandonment is being carried out, a detailed drawing of the wellhead and associated equipment.

5.11

Directional Drilling Operations

5.11.1

General




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During directional drilling operations on platforms and templates, there exists the chance of the well being drilled intersecting with existing wells. In the majority of cases, the responsibility for planning the well path and monitoring the progress of the same during drilling will be with the Operator and the Operator’s Representatives offshore and onshore. It may however be the case that the well is being drilled as an “Integrated Service” package with all directional drilling services being provided by or subcontracted by the Company. In this case, greater responsibility will be placed on the Company drilling personnel. The following are guidelines to assist in development of well specific safety procedures during well planning and implementation.




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Directional Drilling Pre-Spud Meeting Topics To Be Discussed Prior to the start of any well, the Drilling Supervisor is to conduct a pre-spud meeting. The directional drilling plan for the well is to be discussed including the following topics: 1. Wells which may be approached and any planned safety plugging programme. 2.

Directional Drilling Procedures and surveying requirements that will be used to maintain adequate well to well separation.

3.

Individual personnel responsibilities.

4.

Potential well control problems.

Personnel to attend meeting: •

•

5.11.3

The following should attend the meeting: 1.

Drilling Supervisor(s) and Drilling Engineer(s).

2.

Toolpusher(s) and Driller(s).

3.

Directional Driller(s).

4.

Directional Surveyor(s).

5.

Well Logger(s).

Meetings should be held regularly to ensure that all personnel directly involved with carrying out the directional drilling plan remain fully informed. This is especially critical following a crew or tour change.

Responsibilities Drilling Supervisor The Drilling Supervisor (appointed by Operator/Company - dependent on well contract type: normal or integrated service) has overall responsibility for correct implementation of directional drilling procedures that have been developed as part of the Well Programme. He is to liaise with all responsible personnel during the drilling operation to ensure compliance with directional drilling safety procedures. Directional Driller The Directional Driller is responsible for drilling the well according to the Well Programme. He is to liaise with all personnel during the drilling operation. He is to ensure that the Drilling Supervisor is kept informed of all directional drilling matters.




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The Directional Driller is also responsible for performing directional survey calculations, proximity checks and ensuring that correct survey correction factors are applied to each survey in accordance with Well Programme requirements. Directional Surveyor/MWD Operator These personnel are to take directional surveys as required by the Well Programme or as directed by the Directional Driller and Drilling Supervisor. They are to ensure that correct survey correction factors are applied to each survey in accordance with Well Programme requirements. Well Loggers The mud loggers are to carry out independent directional survey calculations using correct survey correction factors as detailed in the Well Programme. This will enable directional survey calculations to be checked for accuracy. These calculations are only to be used to check the accuracy of calculations as carried out by the Directional Driller and Surveyors. Radius Of Error The directional drilling safety limits discussed in this section are based on the definition of a radius of error equivalent to 6 ft/1000 ft of measured depth below the seabed. This assumes a radius of error at the seabed equivalent to zero. This is regarded as a minimum by the Company to maintain safe separation of wells and protect the installation during the drilling operations. Conflict between these requirements and the Operator’s requirements will be resolved at Well Planning Meetings prior to preparation and approval of Drilling Programme. Therefore One RE = 6.0 ft/1000 ft MD BSB where RE = 0 at the seabed. Example: Well drilled to 8500 ft MD RT at a location where distance from rotary table to seabed is 450 ft (RT SB = 450 ft), the calculated RE at total depth would be given by: RE = ((8500 - 450) x 6.0) ÷ 1000 = 48.30 ft This method of calculating RE will be valid for all locations. Distance Of Approach The distance of approach between two wells will be defined as the three dimensional distance from a point on the planned or drilling well to the closest point on an adjoining well path. The subject well will be taken to be the planned or drilling well, with the object well being an existing offset well. Distance of approach calculations (Normal Plane Scan, 3-D Scan) require considerable repetitive mathematical calculations and so are performed by the use of a computer.




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As a drilling well begins to approach critical wells, distance of approach calculations are to be performed at each survey station with the result compared to the allowable minimum well separation for the current drilled depth. Guidelines for determining acceptable well separation distances are given in the following Sections. 5.11.4

Directional Drilling Safety Precautions In order to minimise the potential for well collisions the following precautions should be closely adhered to by field personnel. Any amendment or deviation from these guidelines must be approved by the installation Rig Manager. Depth

Distance of Approach

Required Precautions

above 2000 ft MD BSB

> 3 RE

No special precautions other than planned directional survey frequency and distance of approach calculations.

2 RE to 3 RE

Evaluate critical wells (particularly producing wells). Plug/depressurise wells as required. Follow approved plan and proceed with extreme caution.

< 2 RE

Stop drilling. Inform OIMs on the installation and platform. Consult with shorebase regarding plan of action. Continued drilling requires special precautions and approval.

> 3 RE

No special precautions other than planned directional survey frequency and distance of approach calculations.

2 RE to 3 RE

Temporarily plug/depressurise all endangered wells prior to time of anticipated close approach. Follow approved plan and proceed with extreme caution.

< 2 RE

Stop drilling. Inform OIMs on the installation and platform. Consult with shorebase regarding plan of action. Requires special precautions and approval.

Below 2000 ft MD BSB




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Determination Of Whether To Temporarily Plug Endangered Wells Above 2000 ft MD BSB Every existing well that falls within 3 RE of a planned or well being drilled should be examined to see if it should be temporarily plugged prior to drilling through the interval of close approach. Factors to consider when examining the possible intersection of an existing well by another include:

5.11.6

1.

Quality and accuracy of directional surveys.

2.

Drilling method (rotary vs. mud motor/steerable assy).

3.

Well depth.

4.

Length of close approach.

5.

Type of well being approached (production/injection).

Determination Of Whether To Temporarily Plug Endangered Wells Below 2000 ft MD BSB Endangered wells are to be temporarily plugged when the centre to centre distance (in 3-dimensions) between the object well and the planned or actual well is expected to be 3 RE or less. A well that will be approached within 3 RE should be plugged ahead of the time that the close approach will occur.

5.11.7

Procedure To Halt Drilling - All Depths In the event that the centre to centre distance (in 3-dimensions) between the drilling well and an existing offset well is 2 RE or less, drilling is to halt and the following procedure followed: 1.

Stop drilling. Circulate hole clean and work pipe.

2.

Notify OIM on the installation and/or Platform that drilling well has contravened 2 RE separation rule and that drilling has stopped whilst shorebase management is consulted. If installation is drilling over a subsea template then the Platform OIM responsible for production operations on that template should be informed.

3.

Consult with shorebase management regarding future programme. Any further drilling must be approved by the Rig Manager.

4.

Inform OIMs of plans for subsequent operations.




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Measured Depth Exceed 500 ft The RE used to calculate this distance is to be determined using the depth of closest approach in the drilling (subject) well. However in certain cases the measured depth of the object well (the well being approached by the drilling well) may be significantly greater than the measured depth in the drilling well. When this difference in measured depth exceeds 500 ft, the 2 RE calculation is to be modified slightly to account for the greater degree of borehole uncertainty in the object well. Under these circumstances, the 2 RE calculation is to be performed as follows:

5.11.9

1.

Calculate the radius of error in the drilling well at the depth of closest approach. This number is identified as RE S.

2.

Calculate the radius of error in the object well at the depth of closest approach. This number is identified as RE o.

3.

Calculate the 2 RE distance as follows:

4.

RE = RES + REo.

Safe Drilling Practices For Distance Of Approach Less Than 2 RE For drilling to proceed when the centre to centre (3-dimensional) is 2 RE or less, the following guidelines must be implemented: 1.

No mud motors are to be used for drilling.

2.

Endangered well is to be closely monitored at all times.

3.

Drilling parameters such as rotary torque and rate of penetration are to be closely monitored. If any abnormal drilling conditions such as; excessive rotary torque, very slow Rate of Penetration, erratic rotary speed, abnormal string vibration are detected then drilling is to be stopped immediately.

4.

Drilling Fluid returns from the well are to be closely monitored for steel cuttings and abnormal flow conditions.

Directional surveys are to be taken at least every 30 ft.

6.0

REFERENCES None.


Routine Drilling Operations 7.0


: : : :

67 of 80 2 12.03.99 DOP 202

ENCLOSURES Enclosure 1

Bottom Hole Assembly Sheet (QA Documented Form 032)

Enclosure 2

Trip Sheet (QA Documented Form 033)

Enclosure 3

Casing Checklists for 30” (QA Documented Form 034 Page 1)

Enclosure 4

Casing Checklists for 20” (QA Documented Form 034 Page 2)

Enclosure 5

Casing Checklists for 13- 3/8” (QA Documented Form 034 Page 3)

Enclosure 6

Casing Checklists for 9-5/8” (QA Documented Form 034 Page 4)

Enclosure 7

Drilling Parameters (QA Documented Form 035)



Enclosure No 1

BOTTOM HOLE ASSEMBLY SHEET



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68 of 80 2 12.03.99 DOP 202 Enc 1



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69 of 80 2 12.03.99 DOP 202 Enc 1

Bottom Hole Assembly FOR: ______________ WELL NO: _____________OPERATOR: ________DATE: _____ QTY

DESCRIPTION

THREADS

LENGTH

CUMULATIVE LENGTH

OD

ID

FN

FT

SER NO

REMARKS

BHA TOTAL LENGTH: ______ WEIGHT BELOW JARS: ______ BHA TOTAL WEIGHT: ______ MUD WEIGHT: ______ SIGNATURE DRILLER……………………………….

G:\Management Library\Forms\Offshore\QA Documented Forms\032 - Bottom Hole Assembly - Rev 1

Page 1 of 1


Enclosure No 2

TRIP SHEET



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70 of 80 2 12.03.99 DOP 202 Enc 2



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71 of 80 2 12.03.99 DOP 202 Enc 2

Trip Sheet DATE:……………………….. WELL NO:…………………….. ACTIVE PIT VOLUME:……………….. ………… DEPTH:………………………..

START TRIP TIME:

START OF TRIP:……………………… END OF TRIP:…………………………. END TRIP TIME:

…………… 5” DP STD NOS

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100 105 110 115 120 125 130

TRIP TANK RDNG

ACT VOL USED BBLS

THEO 5” VOL HWPD STD USED NOS DRY

0

ACT THEO VOL VOL USED USED DRY

0 1 2 3 4 5 6 7 8 9 10

6.5” DC STD NO

TRIP TANK RDNG

ACT VOL USED

0 1 2 3 4 5 6 7 8 9 10

8” DC

TRIP

ACT VOL

THEO VOL

STD NOS

TANK RDS

USED

USED DRY

0 1 2 3 4 5 6 7 8 9 10

Signature

TRIP TANK RDNG

5.1 10.2 15.3 20.4 25.5 30.6 35.7 40.8 45.9 51.0

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

G:\Management Library\Forms\Offshore\QA Documented Forms\033 - Trip Sheet - Rev 1

5” DP:BBLS/FT DISP. 5” HWDP:BBLS/FT BBLS/FT 6½” DC:BBLS/FT BBLS/FT 8” DC:BBLS/FT BBLS/FT 9½” DC:BBLS/FT BBLS/FT

DISP. CAP DISP. CAP DISP. CAP DISP. CAP

Driller

Page 1 of 1

THEO VOL USED DRY


Enclosure No 3

CHECKLIST FOR 30” CASING



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72 of 80 2 12.03.99 DOP 202 Enc 3

CHECK LIST FOR 30” CASING ITEM LOCATION

CHECKED

T.G.B. - Check Out & Paint 200 Sacks Of Sacked Barite Angle Iron For Anti Rotation Piles 1/2 In Rope & Shackles (Length 49 In Rope Eye To Eye) Beacons Charged And Ready Length Of Wire On Guide Line Tens. Length Of Wire On Cellar Deck Tuggers T.V. Camera On Wt. Blocks & Check Operation “J” Tool Painted To Show Engage/Disengaged Totco Survey - Check Spear Size, Go Devil & Clock Bit Guide & Sheave Assembly To Run Same P.G.B. C/W Guide Posts, Beacon Arm, Leg Bolts Etc. Check Orientation P.G.B. To Guide Line Position Check Position Of Beacon Carrier On P.G.B. (Elect) Check Level Of Slope Indicator On P.G.B. Check 30 Ins Running Slings & Shackles Paint Numbers On P.G.B. Posts Anti - Rotation Device Fitted To 30 In Conductor Check Support Pads Welded To 30 In Conductor Eyes Welded To Shoe Joint With Soft Line & Shackles Check Wellhead Dimensions Squnch Joint Lock Blocks & O.Rings With Spares Squnch Joint Releasing Tool Or Releasing Bolts Stinger Assembly (Make Up If Possible) Running Tool For W/Hd.- Check O.Ring Seals, Spares Check Float Shoe Paint 2 Ft Marks Black/White On Shoe Joint & W/Hd. Cementing Calculations Checked Casing - Measured, Cleaned, Tallied & Numbered Rabbit Bumber Subs If Used Circulating Head With Lo-Torque Isolating V/V. Fill Up Line D.P.Adaptor Jaw To Suit 5 In D.P. Elevators Length Of Running String Wire Brush And Oil Paint 26 Ins Bit Press Up Drill String Compensator Cut & Slip Drill Line If Required Remarks :

G:\Management Library\Forms\Offshore\QA Documented Forms\034 - Checklist for 30” Casing - Rev 2

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Enclosure No 4

CHECKLIST FOR 20” CASING



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74 of 80 2 12.03.99 DOP 202 Enc 4

CHECK LIST FOR 20” CASING ITEM LOCATION

CHECKED

Check Dimensions Of Wellhead Check Lock Ring Of Wellhead Paint Wellhead & Shoe Joint (2 Ft. Stripes) Check Running Tool (Threads & O Rings) Stinger Assembly Make Up To R.T. & W/Head If Possible Slotted Beam & Spare D.P.Elev. For Stinger If Req. Weld Eyes To Shoe Joint, Att. Soft Lines & Shackles Check Float Collar & Shoe (Note Thread Connection) Csg.- Measured, Inspected, Cleaned, Tallied, Numbered Centralisers, Stop Rings, Nails Etc. Mark Position Of Triangle On Csg. Pins (With Paint) Side Door Elevators (Check On 20 Ins Csg.) Hand Slips 26 Segments Safety Clamps Master Bushings Power Tongs Run & Checked Torque Gauge For Tongs Checked Spares For Tongs, Dies, Rollers, Jaws Casing Clampons (Check Latch) Tongs Make Up & Break Out With Snub Lines Pick Up Line Jaw For 5 Ins D.P. To Release Running Tool Fill Up Line Stabbing Board Check List To Complete Derrick Belt And Safety Line Endless Spinning Rope Cmt. Circ, Head With Lo. Torque Isolating V\V Tailing In Rope Well Head Casing Stack Test Tool Casing Spear Casing Circulating Head Wire Brush (2 Off) & Bucket Of Diesel Flash Light With Safety String Bucket Of Barite Casing Thread Dope & Brush Chin Straps On Rig Crew Safety Helmets Dist Rkb To Land Off Point ..…………… Land String Lgth ..…………… Cementing Calculations Checked …………….. Remarks :

Stick Up ……………..

G:\Management Library\Forms\Offshore\QA Documented Forms\034 - Checklist for 20” Casing - Rev 2

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Enclosure No 5

CHECKLIST FOR 13-3/8” CASING



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76 of 80 2 12.03.99 DOP 202 Enc 5

CHECK LIST FOR 13-3/8” CASING Pooh Last Bit - Collars To Be Accessible For Setting S/Assy. After Csg Job Cut And Slip Drilling Line If Required Pull 18¾In - Wear Bushing Weight Grade I.D.Conn.Type Make Up Torque Min. Opt. Max. Csg Measured, Tallied, Cleaned, & Drifted (Size) Hanger Checked - Lock Ring Required? Csg Hanger Running Tool Checked Hanger, Pups, Running Tool Assy Made Up Seal Assy. Checked Wear Bushing Checked Cup Tester Checked Float Shoe Inspected & Made Up (Set Autofill If Fitted) Float Collar Inspected & Made Up Spare Float & Shoe Joints To Be Bakerlocked - Cleaned & Taped Up On Deck Centralisers & Stop Rings Made Up And Fitted To Accessible Joints On Deck Spare Casing Collars Casing Clampons Checked Casing Cmt. Head X/O For Cmt. Head. Does It Fit Through Elevators CMT. PLUGS (how many) Casing Circ. Head And/Or Water Bushing (Check Thread Type) Company Power Tong Dressed 13-3/8 Ins & Checked Tor. Gauge For Above Jaws For Tongs & Spare Hinge Pins For Fitting Same Tong Snub Line Single Joint Elevators Tried For Fit Slings, Chain & Shackles Condition Company Serial No. Rental Serial No. Certification Check Power Elevators - Certification Check Company - Rating Operational Check Safety Slings Air Connections And Extension Hose

Side Door Elevators Rating Tried For Fit Condition Company Rental -

Serial No. Serial No.

Rental - Rating Operational Check Safety Slings -

G:\Management Library\Forms\Offshore\QA Documented Forms\034 - Checklist for 13 3/8” Casing - Rev 2

Page 1 of 2

Dressed For 13-3/8 Ins Power Slips - Certification Check Company - Rating Rental - Rating Operational Check Operational Check Air Hoses And Connections Dressed For 13-3/8 Ins Bails - Certification Company - Rating Rental - Rating Length Length Hand Slips (18 Segments) Company Rental Insert Bowls Safety Clamp (14 Segments) Stabbing Board Check List To Complete No. Of Joints Onboard No. Of Pups Onboard No. Of Joints To Run No. Before Changing Elev. At Shoe Total Csg String Wt. In Mud In Air Total Exp. Mud Returns OTHER EQUIPMENT - CHECK ALL CERTIFICATION & COLOUR CODING OF ALL SLINGS Centralisers & Stop Rings Casing Pick Up Sling (Braided) Small Hammer, Nails, Pipe Clampon Return Line Long Chain Tong Casing Fill Up Line Diesel, Barite, Rags, Dope Flashlight Bakerlock Tail Ropes Endless Rope Casing Tables Casing Capacity ..……………………… Bbls/ Total Capacity Of Casing ……………..……… Bbls Cementing Calculations Checked ……………………………………………………………………………. Remarks - Please Enter Signature At Each Check Of Point On List Landing String: No Of Joints ...............………... Total Length ……………………………………………. No Of Pup Joints ................….. Total Length ………………………….......................... Hanger Length To Hang Off Point ……………………. Total ………………………….. Rotary Table To Hang Off Point …………………………………………………………… Stick Up ......................……………………………………………………………………… Remarks

WEIGHT AGAINST DEPTH REPRESENTATION W E I G H T

D E P T H

G:\Management Library\Forms\Offshore\QA Documented Forms\034 - Checklist for 13 3/8” Casing - Rev 2

Page 2 of 2


Enclosure No 6

CHECKLIST FOR 9-5/8” CASING



: : : :

79 of 80 2 12.03.99 DOP 202 Enc 6

CHECK LIST FOR 9-5/8” CASING Pooh Last Bit - Collars To Be Accessible For Setting S/Assy. After Csg Job Cut And Slip Drilling Line If Required Pull 18¾ In - Wear Bushing Weight Grade I.D.Conn.Type Make Up Torque Min. Opt. Max. Csg Measured, Tallied, Cleaned, & Drifted (Size) Hanger Checked - Lock Ring Required? Csg Hanger Running Tool Checked Hanger, Pups, Running Tool Assy Made Up Seal Assy. Checked Wear Bushing Checked Cup Tester Checked Float Shoe Inspected & Made Up (Set Autofill If Fitted) Float Collar Inspected & Made Up Spare Float & Shoe Joints To Be Bakerlocked - Cleaned & Taped Up On Deck Centralisers & Stop Rings Made Up And Fitted To Accessible Joints On Deck Spare Casing Collars Casing Clampons Checked Casing Cmt. Head X/O For Cmt. Head. Does It Fit Through Elevators CMT. PLUGS (how many) Casing Circ. Head And/Or Water Bushing (Check Thread Type) Company Power Tong Dressed 13-3/8 Ins & Checked Tor. Gauge For Above Jaws For Tongs & Spare Hinge Pins For Fitting Same Tong Snub Line Single Joint Elevators Tried For Fit Slings, Chain & Shackles Condition Company Serial No. Rental Serial No. Certification Check Power Elevators - Certification Check Company - Rating Operational Check Safety Slings Air Connections And Extension Hose

Side Door Elevators Rating Tried For Fit Condition Company Rental -

Serial No. Serial No.

Rental - Rating Operational Check Safety Slings -

G:\Management Library\Forms\Offshore\QA Documented Forms\034 - Checklist for 9 5/8” Casing- Rev 2

Page 1 of 2

Dressed For 9-5/8 Ins Power Slips - Certification Check Company - Rating Rental - Rating Operational Check Operational Check Air Hoses And Connections Dressed For 9-5/8 Ins Bails - Certification Company - Rating Rental - Rating Length Length Hand Slips (14 Segments) Company Rental Insert Bowls Safety Clamp (11 Segments) Stabbing Board Check List To Complete No. Of Joints Onboard No. Of Pups Onboard No. Of Joints To Run No. Before Changing Elev. At Shoe Total Csg String Wt. In Mud In Air Total Exp. Mud Returns OTHER EQUIPMENT - CHECK ALL CERTIFICATION & COLOUR CODING OF ALL SLINGS Centralisers & Stop Rings Casing Pick Up Sling (Braided) Small Hammer, Nails, Pipe Clampon Return Line Long Chain Tong Casing Fill Up Line Diesel, Barite, Rags, Dope Flashlight Bakerlock Tail Ropes Endless Rope Casing Tables Casing Capacity ..……………………… Bbls/ Total Capacity Of Casing ……………..……… Bbls Cementing Calculations Checked ……………………………………………………………………………. Remarks - Please Enter Signature At Each Check Of Point On List Landing String: No Of Joints ...............………... Total Length ……………………………………………. No Of Pup Joints ................….. Total Length ………………………….......................... Hanger Length To Hang Off Point ……………………. Total ………………………….. Rotary Table To Hang Off Point …………………………………………………………… Stick Up ......................……………………………………………………………………… Remarks

WEIGHT AGAINST DEPTH REPRESENTATION W E I G H T

D E P T H

G:\Management Library\Forms\Offshore\QA Documented Forms\034 - Checklist for 9 5/8” Casing- Rev 2

Page 2 of 2


Enclosure No 7

DRILLING PARAMETERS



: : : :

82 of 80 2 12.03.99 DOP 202 Enc 7



: : : :

83 of 80 2 12.03.99 DOP 202 Enc 7

Drilling Parameters DATE: TIME 00:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00

DRILLER: DEPTH

ROP-AV

DRILLER UP-WT

ROT-WT

DN-WT

SPM

G:\Management Library\Forms\Offshore\QA Documented Forms\035 - Drilling Parameters - Rev 1

PSI

RPM

TORQUE

WOB

ACT-VOL

HVE-AV

REMARKS

Page 1 of 1

DOP 202 - Rev 2

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