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DOP 202 - Rev 2

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Routine Drilling Operations Document No.

Document Title

DOP 202

Routine Drilling Operations

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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

PURPO PURPOSE SE... ...... ...... ...... ...... ....... ....... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ........ .......... ......... ......... ......... ......... ....... .. 2 SCOPE SCOPE... ....... ....... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ....... ......... ......... ......... .......... ......... ......... ..... 2 RESPO RESPONSI NSIBIL BILITI ITIES. ES.... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ....... ....... ...... ...... ...... ...... ...... ...... ...... ....... ......... ........ ... 2 Senior Senior Toolpu Toolpushe sher.... r........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......... .......... ..... 2 Drill Drillin ing g Superv Superviso isor... r....... ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........... ............... ............ .... 2 Direc Direction tional al Dril Drille ler... r....... ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........... ............. ...... 2 Direc Direction tional al Surveyo Surveyor/M r/MWD WD Operator Operator.... ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .......... ...... 2 Well Loggers... Loggers....... ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......... ............. .......... .. 3

DEFINIT DEFINITION IONS.. S..... ...... ...... ...... ...... ...... ....... ....... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ........ .......... ......... ....... ... 3 PROCE PROCEDUR DURE.. E..... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ...... ....... ....... ...... ...... ...... ...... ...... ...... ........ ......... ......... ..... 3 Handl Handling ing,, Maki Making ng Up Up And And Layin Laying g Out Out Bottom Bottom Hole Hole Asse Assembl mblies. ies..... ........ ........ ........... .............. ......... 3 Trippi Tripping ng Proced Procedure ures.... s........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .......... ......... ... 14 Drill Drillin ing g Proced Procedure ures.... s........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......... ............ ......... .. 16 Loggin Logging g Operati Operations. ons..... ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......... ..... 22 Casin Casing g Operation Operations... s....... ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .......... ............. .............. .............. ....... 31

Routine Drilling Operations 1.0

PURPOSE

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Routine Drilling Operations 1.0

PURPOSE

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Routine Drilling Operations

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The purpose purpose of this this proced procedure ure is to descri describe be and give give guidan guidance ce on routin routine e 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 Drillin Drilling g Supervisor Supervisor (appointed (appointed by Operator/Co Operator/Company, mpany, dependent on well 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 responsible personnel during the drill drilling ing operati operation on to ensure ensure compli complianc ance e with with direct direction ional al drilli drilling ng safety safety

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None.

5.0

PROCEDURE

5.1 5.1

Han Handlin dling, g, Maki Makin ng Up and Layi Laying ng Out Out Bott Botto om Hole Hole Asse ssembli mblie es

5.1.1

Planning Prior to making up, breaking out, or changing a BHA, consideration should be give given n to the the safes safestt and and most most effic efficie ient nt meth method od for cons constru truct ctin ing, g, chan changi ging ng,, or dismantli dismantling ng the assembly. assembly. There is a vast selection selection of tools and equipment equipment which require to be handled, and numerous methods for doing so, in general these can be broken down into five main categories: NOTE OTE:

1.

The Dril riller sha shall ale alert the the Duty uty Too Toolpu lpusher sher befor efore e mak making ing up or  breaking out bottom hole assemblies.

Tools Tools with with a lift lift recess recess can can be put direc directly tly into into the the elevato elevators rs by one 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..

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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

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 off t ll d simila lithol will be al ted d ded bit

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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.

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: 1.

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

2.

Never drill on junk.

3.

Lo

r the bit to bottom with

t

tating and pump any junk or pie

of 

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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.

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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.

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.

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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. 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.

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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.

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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

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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.

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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.

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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.

5.2

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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.

Tripping Procedures

Routine Drilling Operations 9.

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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 conditi

s will det mine when to “sl

” pip

It is advi

ble to

ll

Routine Drilling Operations 5.3.1

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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.

Routine Drilling Operations

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.

Caus

essiv

ar in the subsequent casing strin

hile drilling

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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:

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

Routine Drilling Operations

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.

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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 gl hole bein drilled, othe is 6 nths

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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.

7.

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.

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).

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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.

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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.

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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

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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

Routine Drilling Operations

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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 

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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. well. The data recorded by by the geophone is processed by a computer  to obtain obtain informati information on simila similarr to a seismi seismic c sectio section. n. Reflec Reflectio tions ns from from horiz horizon on below the present well TD could be detected. Proximity Survey This survey is similar to a velocity survey system except that several carefully select selected ed surface surface locati locations ons are used with the energy energy source. source. The energy 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 may be set any number of times times during a single single logging logging run.  At each setting depth, a "pre-test" is made in which small samples of fluid are withd withd fro the formatio formatio During During the pre-test pre-test the fluid fluid pressure pressure in the

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The pressure pressure is initiall initially y at hydrostatic hydrostatic mud pressure. pressure. When the packer first enga engage ges s the the filt filter er cake cake,, the the pres pressu sure re may may rise rise due due to pack packer er or mud 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 packer but suddenly suddenly drops again 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. pre-test. At time, T2, the piston piston in the second second chamber 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 sealed and have have a PVT transf transfer er at later date. date. Note Note that transfe transferr 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 Ho Hole Logs Neutron Log This is simila similarr to a neutron log run in open hole. hole. Generally Generally the effects of pipe and cement make determination of porosity less reliable than in open hole. Pulsed Neutron

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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 several degrees over normal. The temperature change at the 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 examin examining ing differe different nt azimut azimuths hs of the casing casing with with very very fine vertic vertical al resolu resolution tion,, thus enabling enabling a channel to be identified. identified. The transducers transducers act as transmitters transmitters and receivers, each transducer emitting a short pulse of acoustic energy and then then rece receiv ivin ing g the echo echo from from the the casi casing ng.. The The shor short, t, ligh light, t, rigi rigid d soun sound d is centralise centralised d easily. The type of wave propagation propagation used (compressi (compressional onal wave normal to the casing surfaces) is not affected by a microannulus that is small with respect respect to the wavelength wavelength.. Reflections Reflections from the formation arrive 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 been esta establ blis ishe hed d expe experi rime ment ntal ally ly betw betwee een n this this elas elasti tic c para parame mete terr and and the the compressive strength for oilwell cement.

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Mud checks checks are to be carried carried out on active active and reserve reserve mud tanks at regular intervals and the Mud Engineer should run regular checks on mud being circulated across well well from trip tank. Log mud weights and viscosity’s viscosity’s on IADC Report. 2.

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

3.

The Loggi Logging ng Engine Engineer er must must be instruc instructed ted to be alert alert and and report report any unusu unusual al hole hole cond condit itio ions ns such such as drag drag,, brid bridge ges s or sticky sticky hole. hole. If ther there e are are problems, consider to make a wiper trip.

4.

The The Loggin Logging g Engi Engine neer er must must also also be inst instru ructe cted d not not to pull pull out out of the rope rope socket socket if logging tools tools become stuck. stuck. When logging tools tools are stuck in in the hole the recommended fishing procedure is to "cut and thread" with an overshot.

5.

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

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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.

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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.

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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).

collars,

centralizers

and

markers

as

per  

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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 q uick 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).

is available

for

individual

well

sections

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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.

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 t he 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.

Routine Drilling Operations 5.6.2

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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,

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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.

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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 pr

ure in

s and the circulation rate is cor

t, raise the bit off 

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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.

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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.

Routine Drilling Operations 5.6.6

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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

Routine Drilling Operations 7.

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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.

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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

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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.

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.

Routine Drilling Operations 5.7.7

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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

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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.

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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.





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

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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.

Routine Drilling Operations 5.

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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



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:

Routine Drilling Operations

5.9.3

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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.

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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

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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 

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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 of requirements.

temporary

abandonment

there

are certain

additional

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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

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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:

8.

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.

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.

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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.

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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.

Routine Drilling Operations 5.11.2

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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:



The following should attend the meeting: 1.

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

2.

Toolpusher(s) and Driller(s).

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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 

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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

above 2000 ft MD BSB

Distance of    Approach

Required Precautions

> 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.

Routine Drilling Operations 5.11.5

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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.

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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:

Routine Drilling Operations 7.0

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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)

Routine Drilling Operations

Enclosure No 1

BOTTOM HOLE ASSEMBLY SHEET

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

DESCRIPTION

THREADS

LENGTH

CUMULATIVE LENGTH

OD

ID

FN

FT

SER NO

REMARKS

Routine Drilling Operations

Enclosure No 2

TRIP SHEET

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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

TRIP TANK RDNG

 ACT VOL USED BBLS

THEO 5” VOL HWPD STD USED NOS DRY

0

0 1 2 3 4 5 6

TRIP TANK RDNG

 ACT THEO VOL VOL USED USED DRY

6.5” DC STD NO

0 1 2 3 4 5 6

TRIP TANK RDNG

 ACT VOL USED

THEO VOL USED DRY

Routine Drilling Operations

Enclosure No 3

CHECKLIST FOR 30” CASING

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CHECK LIST FOR 30” CASING ITEM LOCATION 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

CHECKED

Routine Drilling Operations

Enclosure No 4

CHECKLIST FOR 20” CASING

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CHECK LIST FOR 20” CASING ITEM LOCATION 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 I f 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)

CHECKED

Routine Drilling Operations

Enclosure No 5 CHECKLIST FOR 13-3/8” CASING

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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 I f Required Pull 18¾In - Wear Bushing Weight Grade I.D.Make Up Torque Min. Opt. 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 -

Conn.Type Max. -

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 -

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

Routine Drilling Operations

Enclosure No 6 CHECKLIST FOR 9-5/8” CASING

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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 I f Required Pull 18¾ In - Wear Bushing Weight Grade I.D.Make Up Torque Min. Opt. 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 -

Conn.Type Max. -

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 -

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

Routine Drilling Operations

Enclosure No 7

DRILLING PARAMETERS

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