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Routine DrillingOperations

Page : 1 of 80Rev No : 2Date : 12.03.99Doc No : DOP 202

Document No. Document Title

DOP 202 Routine Drilling Operations

TABLE OF CONTENTS

1.0 PURPOSE.................................................................................................... 22.0 SCOPE......................................................................................................... 23.0 RESPONSIBILITIES...................................................................................... 2

3.1 Senior Toolpusher.................................................................................................. 23.2 Drilling Supervisor.................................................................................................. 23.3 Directional Driller.................................................................................................... 23.4 Directional Surveyor/MWD Operator...................................................................... 23.5 Well Loggers.......................................................................................................... 3

4.0 DEFINITIONS............................................................................................... 35.0 PROCEDURE............................................................................................... 3

5.1 Handling, Making Up And Laying Out Bottom Hole Assemblies............................ 35.2 Tripping Procedures............................................................................................. 145.3 Drilling Procedures.............................................................................................. 165.4 Logging Operations.............................................................................................. 225.5 Casing Operations.............................................................................................. 315.6 Coring Operations............................................................................................... 36

5 7 Fishing Operations 42

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5 7 Fishing Operations 42



1.0 PURPOSE

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The purpose of this procedure is to describe and give guidance on routinedrilling 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 wellcontract type, normal or integrated service) has overall responsibility for correctimplementation of directional drilling procedures that have been developed aspart of the Well Programme. He is to liaise with all responsible personnel duringthe drilling operation to ensure compliance with directional drilling safetyprocedures.

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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 begiven to the safest and most efficient method for constructing, changing,or dismantling the assembly. There is a vast selection of tools and equipmentwhich require to be handled, and numerous methods for doing so, in generalthese can be broken down into five main categories:

NOTE: The Driller shall alert the Duty Toolpusher before making up orbreaking out bottom hole assemblies.

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

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

3. Tools 8 diameter or less can either be lifted into the mousehole usingan air winch the elevators can then be swung over using the

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The above methods will generally be suitable for shorter tools such asstabilisers, subs, crossovers etc.

4) Lifted directly onto the string in the rotary table using an air winch andlifting cap, or manually for small subs and tools. Drill collar liftingsubs will be handled using a set of single joint elevators fitted witha 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 liftedinto position, and various small diameter testing tools andcrossovers. All lifting subs and crossovers will be screwed andunscrewed using chain tongs, after visually checking that both ofthe chain link pins are securely located in the tong lugs.

5) Picked up from the derrick using a combination of racking armsdepending upon configuration of the stand i.e. lift recesses,

diameter, placement of stabilisers or other tools, location in derricketc.

Laying out or breaking down tools and tubulars may be performed as areverse of above.

5.1.2 Preparation

5 1 2 1 Bit Selection And Gauging

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3. Abrasiveness

The presence of abrasive intervals may call for shorter, stronger teethand special gauge protection. However, in unconsolidated surfacesands, the tooth hardfacing on soft-formation bits usually lengthenstooth life sufficiently to make these bits the best choice despite theabrasive 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 beground up before the drilling fluid can carry them out of the hole. This usuallyresults in severely broken teeth. Fractured intervals often require the use of bitswith short teeth along with light force on bit.

Too much emphasis cannot be placed on the proper selection of force on bitand rotary/DDM speeds. Unfortunately, there is no formula for determining theproper 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 aparticular bit type. A drill off test should be carried out to find the optimumparameters.

There are many different types of bits available from several differentmanufacturers with new types coming out frequently. Bit performance fromoffset wells and similar lithology will be evaluated and recommended bit

selection shown in the drilling program This should be followed unless holedi i di h h i i d

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5. Multiply this measured distance by two-thirds to determine the amountundergauge.

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 maximumbit diameter.

3. Centre ring gauge over bit cones so that ring gauge ID is an equal distancefrom 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 thediametrical amount bit is undergauge.

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

1 2 G i Di d Bi

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5.1.2.7 Weight And Speed

Rotary/DDM speed is a major contributing factor to the rate of penetration fordiamond bits. Test data indicates that with proper hole cleaning, the penetrationrate is almost in direct proportion to rotary/DDM speed. High RPM will not burna diamond bit if proper hydraulics are available to cool the diamonds and keepthe 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 runthrough a uniform formation to find the maximum force on bit compatible withavailable hydraulics. With diamond bits always run maximum RPM and force onbit 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 andwhen 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. Lower the bit to bottom without rotating and pump any junk or pieces offormation from below the bit. Minimum weight should be used until thebi i d i h f i (fi )

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Due to less weight requirements, amount of drill collars are reduced and thisresults 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 downthe hole.

2. A junk basket run may be considered if there is any suspicion of junk in thehole.

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

4. Use a proper bit breaker by taking the recommended make-up torque anddivide 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 thebottom of the hole is located, the bit must be lifted from 0.5m (20") offbottom while circulating and rotating slowly for five minutes to makecertain the bottom of the hole is clean.

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By using oil base mud PDC bit tends to drill faster and lastlonger and are therefore recommended. However, certainshales which normally will require an oil base (inhibited) mud,can be more effectively drilled with a water base mud by usinga 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 andcheck 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 sizerequired (Ref. Manufacturers Manuals).

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

7. Iron roughneck - visual inspection, check jaws or spacers available fordiff i i Ch k lib i E ll

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18. Totco location.

Also a visual inspection of threads and sealing faces must be carried outalong with a check on any certification that is required.

3. Drawings of stabilisers, jars, turbines/mud motors, MWDs and otherspecialised downhole tools should be made recording all relevantdimensions. This information may be required for any subsequentfishing 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 isalready dressed check the nozzles are secure, clear, and the correctsize.

5. Check gauge on drill bit, stabilisers and integral stabilisers on mudmotors/MWDs etc.

6. Service Engineers will supply any necessary information regarding make uptorques or special procedures that may be required, e.g. surface testingturbines, mud motors, MWDs etc. Check if any intermediateconnections are to tighten. Ensure crossovers required for use of thestab-in valve are ready on the rig floor before commencing the BHAhandling operation.

7. Prepare drifts that are required. It is good practice to drift tubulars as theyi k d d b i i l d d i id D if i ill

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4. The weight of the equipment (to allow proper selection of adequatelifting gear).

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

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

In the V-Door.

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

Drill collars or tubulars, can be picked up and placed in themousehole, or tailed in from the catwalk. For tailing inManual elevators of the required type should be fitted to theelevator links. Picking up tubulars from the mousehole can beachieved using the DDM link swing in combination withautomatic elevators.

General Guidelines for Tailing In are as follows:

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3. On floating drilling units it is essential that tubulars are prevented fromswinging due to rig motion. Use drill floor racking arm to steadytubulars, if this is not available then it may be necessary to rig upairwinches. (Once heavy tubulars are allowed to swing then it may betoo late to prevent serious injury or damage occurring.) The protectorcan 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 thebox shoulder, it is essential to check for any damage if this shouldoccur.

5. It is good practice to Walk in/Out BHA tubulars using chain tongs,DDM/Top drive pipehandler rotation can be used (Ref. OperatorManual). Drillers should be aware of recommended make-up torquerequired 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 tomaking 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 andflapper should be in good condition. The valve should be inserted fullybefore attempting to screw on the bit, under no circumstances shouldthe bit shank be used to push the float home during make up. A totcoring of the crows foot design may be run on top of the float valve. Thefl l b h d h hi i di l d d

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8. Prior to picking up jars, the type should be identified and relevantinformation on strengths, maximum jarring loads, methods of operation,and any other checks which are required prior to make up and runningin the hole should be identified. Clamps which are fitted should bechecked to ensure they are secure prior to raising the tool to the verticalposition. The clamp should be removed prior to running the jar in thehole, and refitted when it is pulled out of the hole. (Caution should beexercised when pulling jars through the rotary table as the mandrel maycatch on the bushings causing them to lift unexpectedly.) Jars are

normally supplied with a lifting sub, it may be necessary to removed thisitem to allow insertion of the rabbit.

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

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

10. Use iron roughneck (if available) to minimise hazards associated with rigtongs unless unable to fit same due to stabiliser blades etc. Driller toensure that correct make-up torque is set and applied.

11 Wh i i b f ki i

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

1. Use automatic elevators, lift subs and pipe handling equipment as much aspossible to enhance safety and efficiency. Take due care and attentionwhen using automatic elevators with light loads (Ref. ManufacturersManuals).

2. Gauge all stabilisers on trips in and out of the hole. Note any changes and

report same to Senior Toolpusher and Operators Drilling Supervisor.

3. Before racking jars in the derrick, the safety clamp should be fitted. Asthese clamps are normally light alloy care must be taken to preventthem from striking other tubulars, catching on the racking arm head, orintermediate board. The jars should always be packed on the top of astand.

NOTE: Damage may result in pieces falling to the rig floor.

4. 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 andwellhead.

5.2 Tripping Procedures

5.2.1 Running In The Hole

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9. Running speeds should be chosen for the prevailing hole conditions. Beaware of surge effects etc. and should hole problems/incorrectdisplacement occur then Senior Toolpusher and Operators DrillingSupervisor should be notified.

10. Assistant Driller/Derrickman should check that mud pumps are lined upready to circulate through the string before reaching the bottom of thewell. It is advisable to have this done before the bit goes into open holein 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 Operators DrillingSupervisor/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 stringgetting 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 pullpipe wet using a mud bucket where there is the possibility of having to

/b k A i di i d l i

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5.3.1 Starting Drilling

1. It is recommended to break circulation and wash/precautionary ream tobottom (at least last stand with top drive). Break circulation slowly toensure that any pressures needed to break gels do not break downformation. Rotating the string will assist to break gels beforecommencing pumping. Ensure that there are good returns beforegoing on bottom.

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

3. Measure in on pipe from convenient reference point and tag bottomcarefully. 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 Operators Drilling Supervisor, Toolpusher orBit Manufacturers Guidelines.

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

3 2 D illi Ah d

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6. It is recommended that sufficient drill pipe is made up and racked in thederrick to drill the next hole section, (minimum - anticipated bit run).This will avoid potentially hazardous operations when making up standsin the mousehole during drilling operations. Procedures will depend onspecific installation layout and be the result of discussion between RigManager, Senior Toolpusher and Operators Drilling Supervisor.

7. Well Control must be maintained as per Well Control Manual (Ref. WCO200).

8. Safe, efficient drilling operations will result from good communicationbetween Driller/Rig Floor/Shale Shaker House/Mud Room(s) andMudlogging Unit.

5.3.3 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 Hi d i f i f i l i l

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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 toparticular well sections.

Driller must check that fishing equipment is available and checked for operationbefore 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 insidediameters.

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 alltimes when wirelining.

5.3.4 Causes Of Hole Deviation

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6. A typical pendulum BHA consists of bitsub, two drill collars, one stringstabiliser 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.

5.3.6 Operational Guidelines For Directional Control

1. Alternative survey instruments to check instrument accuracy.

2. Backreaming to reduce angle is acceptable, but precautions must be takento avoid unscrewing the drill pipe if there are doglegs in the hole. Donot 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 holeformations.

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

6. Deviation in the 36 hole should not exceed 1. 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 andb l h i i d h

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Stabilisers And Their Use

Stabilisers placement and bit weight are used for building, holding and droppingangle. Weight on the bit causes and forces the collars to contact the low side ofthe hole. The distance from the bit to the point the collars contact the side of thehole 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 astabiliser is run below the point of tangency, it acts as fulcrum and causes thehole 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, thestabiliser produces a pendulum effect. This effect holds the collars off the lowside of the hole so that gravity acts upon the mass of the columns, tending topull 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. Stabilisersworn 3.2 mm (1-1/8") or more will be laid down and repaired.

2. Stabilisers should be gauged each trip when directional control isimperative.

3. The entire bottom hole assembly shall be magnafluxed between wells ifhigh angle holes are being drilled, otherwise every 6 monthsapproximately.

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

High Torque

1. Stabilisers are often the source of high torque. Generally torque developedby stabilisers will fluctuate widely. The commonly accepted methods ofcontrolling stabiliser torque are:

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

3. Use roller reamers. These stabilisers are generally acceptable forstraight 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 weakestconnection in the drill string, less an amount for inertia effects (weightand speed of rotation).

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

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The following is a description of the most frequently used deflection tools andmethods:

1. Down Hole Motor Method With Bent Sub

This method uses a down hole mud motor and a bent sub to obtain thedesired deflection and direction. The tools are run in the hole andorientated. Each mud motor will have a specific response to the

volume of mud pumped through it (RPM volume). After the tool hasbeen oriented the rotary or DDM is locked. A pumping rate isestablished to give the desired RPM and the bit is lowered to thebottom of the hole or to the top of the kick off cement plug. Correctionswill have to be applied at surface to compensate for twist in thedrillstring due to reactive torque. Drilling proceeds with surveysnormally made after each joint of pipe has been drilled. Drilling iscontinued until the desired deflection has been obtained. The mud

motor is pulled and a stabilised drill string is run back in the hole to drillahead.

Orientation and surveying will normally be done using either a MWDtool or a steering tool. While the MWD tool sends information tosurface through pressure pulses through the mud, the steering toolneeds a single conductor wireline. To avoid pulling the probe each timea connection is made a wireline entry sub can be used.

Th l h i d d h i d h l i h

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The Logging Engineer is responsible for carrying out the logging operation inaccordance with the agreed company procedures. He will raise a permit for useof explosive or radio active sources, and ensure that radio silence/top driveisolation is requested if required. He is to keep the on-tour Toolpusherinformed of the progress and to ensure all necessary safety practices areadhered to.

5.4.2 Preparations

1. Restrict crane operations during wirelining to avoid collision between loadand wireline. Urgent lifts should only be done when tools are out of thehole and following discussion between Toolpusher, Operators DrillingSupervisor, Logging Engineer and Crane Operator.

2. To ensure hole conditions are good for running logs, it is normal practice tomake a wiper trip and then circulate the hole clean. The mud

properties can also be adjusted as required for logging tools to beused.

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

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

5. Discuss with Logging Company Engineer/Operators regarding:

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Fully stroke out the compensator with low air pressure, lower the elevators andrig up the logging equipment. Disconnect the air line and secure the latch onthe elevators. Pick up the blocks and logging equipment until near requiredheight. Do not bring the compensator to mid stroke until the logging tools aresafely below the rotary. If compensator heave line sheave is positioned aboveelevators, change auto elevators out for manual 5" elevators to avoid damaginglatch 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 isgiven to logging string, this is especially important when there are hole problemsand good communication between logging unit and drill floor is essential.

Drill Crew will assist Logging Crew to make up tools as required, operatingairwinches, steadying tools when stabbing but final make-up is the responsibilityof the Logging Engineer/Operator.

Good communication between Logging Engineer/Operator and Drill Crew isessential for safe and efficient working. A line wiper must be fitted prior topulling wireline from the well.

5.4.4 Logging Tools

The following is a brief description of wireline logging tools and their intendeduse.

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Density Log

This radioactive tool bombards the formation with gamma rays and measuresthe formations ability to absorb these gamma rays. The ability to absorb theserays 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 theborehole and compensates for the filter cake, but is not reliable in washed outhole.

Lithodensity Log

The lithodensity log has in addition to the conventional density curve a Pe curvewhich is an index of the effective photoelectric absorption cross-section of theformation. 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 theformation rock with neutrons and measures the rocks ability to slow or capturethe neutrons. This slowing or capturing ability is a measure of the water or oilcontent. 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

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The spontaneous potential (SP) is a measure of contrast of mud salinity andformation water.

The SP Shows maximum deflection in one direction for clean sands and in theopposite direction in clean shales.

The SP is usually run as an additional curve on resistivity logs, sonic logs and asdepth 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 theformation. The GR-reading is highest in shales and lowest in clean sands orcarbonates.

Natural Gamma Ray Spectroscopy Log

The natural gamma ray spectroscopy log detects naturally occurring gammarays of various energies emitted from a formation. Thorium, uranium andpotassium (Th, U, K) are primarily responsible for the energy spectrum observedby the tool.

Caliper

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Vertical Seismic Profiling

A VSP is performed by locating a geophone at several stations in the well andrecording the response when an energy source is triggered at a surface locationnear the well. The data recorded by the geophone is processed by a computerto obtain information similar to a seismic section. Reflections from horizonbelow the present well TD could be detected.

Proximity Survey

This survey is similar to a velocity survey system except that several carefullyselected surface locations are used with the energy source. The energysources 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 widelyused. 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 arewithdrawn from the formation. During the pre-test the fluid pressure in theformation adjacent to the wellbore is monitored until equilibrium formation

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The pressure is initially at hydrostatic mud pressure. When the packer firstengages the filter cake, the pressure may rise due to packer or mudcompression, 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 ofthe 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 pressuredrop of the second pre-test. At time, T2, the piston in the second chamber isfully withdrawn, and the pressure builds up to formation pressure 0.

The fluid samples can be taken at any setting and they can be recoveredimmediately (transferred at atmospheric pressure) or, alternatively the samplecan be sealed and have a PVT transfer at later date. Note that transfer ofsampling 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 pipeand 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,

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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 thecasing by several degrees over normal. The temperature change at the cementtop 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 transducersexamining different azimuths of the casing with very fine vertical resolution,thus enabling a channel to be identified. The transducers act as transmittersand receivers, each transducer emitting a short pulse of acoustic energy andthen receiving the echo from the casing. The short, light, rigid sound iscentralised easily. The type of wave propagation used (compressional wavenormal to the casing surfaces) is not affected by a microannulus that is small

with respect to the wavelength. Reflections from the formation arrive later thanfrom the cement and thus can be distinguished.

The response of the tool is dependant on the acoustic impedance (product ofdensity and acoustic velocity) of the cement, and an empirical relationship hasbeen established experimentally between this elastic parameter and thecompressive strength for oilwell cement.

Thus the log can be calibrated directly in cement compressive strength. Also the

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Mud checks are to be carried out on active and reserve mud tanks atregular intervals and the Mud Engineer should run regular checks on mudbeing circulated across well from trip tank. Log mud weights and viscosityson IADC Report.

2. The mud level in the trip tank should be lower after each logging run than itwas at the start of the run. This is due to fluid loss to the formation andsurface loss through the wireline wiper. Anytime the fluid level is higherthan when the logging run began, the well is either flowing, has been

swabbed, or fluid has been added at the surface. A line wiper shouldbe utilised on the logging line rather than washing the line with a waterhose.

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

4. The Logging Engineer must also be instructed not to pull out of the ropesocket if logging tools become stuck. When logging tools are stuck inthe hole the recommended fishing procedure is to "cut and thread" withan overshot.

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

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

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4. Proper briefing of crews before starting. Ensure that personnel areaware of procedure to use if well control is required. Methods usedto 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 andensure 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 oftapered/combination strings, it is important to identify grade and weightof each joint and rack them to ensure that First items to be run will be atthe 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 somejoints of casing. Check certification up to date. Check condition oflatches, safety pins etc. Check Condition of slings/swivels/bridles foruse with single joint pick-up elevators.

3. Remove all thread protectors and drift casing (record drift diameter inreport).

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7. It is standard practice for float collars and float shoes to be made up andthreadlocked onshore. Check that this has been done. Handle thesejoints with due care and attention. Check these joints for anydebris/rags. These joints will be thread locked so clean the threadsthoroughly and bag same. Length of shoe track and number ofconnections to be thread-locked will be specified in Well Programme.

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

9. Check 350/500 ton spider (or flush mounted slips) and elevators. Dresssame with slip inserts and guides required (Ref. ManufacturersManuals) function test same and place on deck where they can bepicked 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 whilstlogging/circulating, at a time when Driller considers it safe to do so.Ensure that Casing Service Hands do this along with AD/Derrickmanand complete relevant reports.

12. Position casing tong power pack and test same. Rig up hydraulic hoseswhen safe to do so. Check back-up power unit if available.

13. Make up stop collars and centralizers as required by Operators Well

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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 havechinstraps or safety lines fitted to hard hats where there is thepossibility 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 HandlingProcedures (Ref. Section 5.1). Ensure power tong ready for use beforeapplying thread locking compound. Confirm make-up torque to be used

with Casing Crew. It is easier to handle all joints to be threadlockedwith airwinch and deckcrane into the side door elevators and then rigup single joint pick-up elevators once ready to run without lockingconnections.

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

6. Attach and run stop collars, centralizers and markers as perWell Programme.

7. Rig up single joint pick-up elevators and run casing by picking same up atV-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

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15. Maintain tally as casing is run. If it is necessary to lay out any joints (badconnections, pipe damage etc. notify Toolpusher and Operatorsrepresentative) and try to replace the joints with joints of approximatelythe same length.

NOTE: Stop and hold a quick tool box talk prior to changing theroutine from running casing to pulling casing, as this is whenaccidents can happen.

16. Carry out a count of joints remaining on deck before making up the hangerassembly. This should also be done before making up specialequipment e.g. DV collar.

17. It is recommended when running hanger/seal assemblies with small annularclearances to open choke and kill lines on BOP to surface to minimiseadditional surge pressures.

18. Do not exceed 90% of DSC capacity when landing casing. If fitted, theactive Heave Compensator may be used toProcedures adopted willdepend on weather conditions at time of running casing and type ofDSC in use assist in the landing of casing.

19. More specific information is available for individual well sections(Ref. Section 3).

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It is essential when displacing cement to keep an accurate measurement ofvolumes. There will be the possibility of confusion arising due todifferences between cement slurry weights and mud weights and thetendency for cement to free-fall in the casing. Later on during theoperation mud return rate will seem to decrease but this does not meanthat lost circulation is occurring.

When displacing cement and bumping plug, do not rely on stroke countersentirely, 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 testpressure required in the Well Programme. When releasing thepressure, line up to trip tank or cement unit tanks to monitor the volumebled back. If there is significant back flow, this indicates that the floatvalves are failing to hold. The same volume should be pumped backand the pressure held until the cement has thickened.

It is good practice to circulate and wash the wellhead area after releasingthe running tool. (Care must be taken not to damage the hanger if thevessel is heaving, since this may hinder proper setting of the sealassembly.) Ensure that Mud Engineer checks the mud returns forcement contamination and measure or estimate volume ofcontaminated mud dumped.

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

5.6 Coring Operations

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

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

5.6.1 Preparations

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

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

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5.6.2 Coring Equipment

The most widely used coring tool is the conventional double tube core barrelwith diamond or PDC core head. These core heads cut with a grindingaction and thus reduce fracturing of the core. Non-fractured core isless 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 resultof having junk in the hole, shock loading or burning caused byinadequate 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 diamondsare used in soft formation bits in order to gain a more significantpenetration of the diamond into the formation. For hard formation coresmaller 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

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5.6.3 Picking Up and Running Core Barrel

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

Take care with PDC/diamond coreheads to avoid striking sides of rotarybushings 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 runningin the hole with PDC/diamond coreheads.

Run in the hole carefully to avoid striking ledges/bridges etc. which maydamage the corehead. Use the DSC to pass the BOP. If it isnecessary 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 withappropriate tide correction.

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

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3. 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 hardsands. Bit weight should be varied while drilling, maintaining a closewatch on the pump pressure to determine the optimum bit weight for aspecific 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 canresult 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-coursearea 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 bekept in mind throughout the coring operation. Any change in pump pressure

indicates that something abnormal is occurring and the cause must bedetermined. The pump strokes should be checked to ensure that the circulationrate 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 offbottom and record the pressure. If the pressure drops but then returns

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When making a connection, the rotary table should be stopped and the coreassembly picked up off bottom very slowly. The core will usually breakoff easily, however, observe the weight indicator closely. A noticeablejump on the weight indicator will occur when the core breaks. Ifproblems 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 corebreaks.

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 whilefeeling for any core that may have been left on bottom. If a piece ofcore has been left in the hole, it can sometimes be worked back intothe barrel. Light bit weight and very slow rotation of the rotary is usedin this operation.

After making the connection, go back to bottom slowly and rotate 50 RPMuntil 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. Breakthe core and check for lost core using same procedures as atconnections. Check depth measurements and correct for tide asrequired.

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

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

1. Due to the light loads involved whilst handling the inner barrel, that theair line from the automatic elevators is disconnected, or usemanual 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 noother 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 crewshould don BA sets at the start of pulling drill collars through the

rotary table. Each connection broken in the drill collars, especiallyjust above the core barrel and during core retrieval, must bechecked for H2S with a suitable gas detector. BA should continueto be used until the core has been lowered from the rig floor.Depending on the results of the first core, a decision will be madeat the rig site whether BA sets continue to be donned forsubsequent core retrieval.

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

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5.6.6 Laying Out Core Barrel

Lay out core barrel as directed by Coring Engineer using BHA handlingprocedures 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 pulledat will. Fishing tools and operations are used to remove these objects from thewell. Failure to recover the fish can lead to the well requiring redrilling,sidetracking or even abandonment with the associated costs and lossesinvolved. It is of great importance to consider the possible causes of fishing jobsand 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 additionalstresses imposed to attempt to free it. Alternatively if the string cannot be freedthen it is released above the stuck point (back-off Ref. Section 5.4). It is then

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7. A steady increase in pressure while drilling.

If tight hole is experienced, never pull too hard into the tight spot. Stop and godown again and work the pipe through the section. Do not pull more than canbe 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% ofall fishing operations result from poor hole conditions.

Annular velocity, mud density, viscosity and gel strength are the main factorsconsidered when cuttings are not being carried out of the hole.

Fishing jobs that result from drill string failure should be analysed andoperational 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 checkedto 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 checkingconnections, pipe body condition etc. during trips might prevent the piece ofequipment being rerun.

It is better to lay any equipment out that may look doubtful than to take a chanceand run it in the hole where it might fail.

Be alert to changing hole conditions (Ref. Section 5.1 Drilling Problems) inDOP 204 Drilling Problems) monitor parameters whilst drilling to determineoptimum time to pull and change the bit before failure occurs.

Take appropriate precautions to prevent items being dropped in the holethrough 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 thatsufficient volumes of pipe freeing chemicals are on board for spottingfluid to free differential stuck pipe. Check that all required fishing toolsare on the rig.

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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 existingsituation?

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 onconnections 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 theiroperation and capacities may be obtained from their Manufacturers Manuals.

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5) Junk Baskets - These come in various forms and are used to retrieve small

objects such as bit cones, dropped objects etc. Most common typesare:

6) Poor boy - tube with fingers cut in the lower end, incapable of removingobjects embedded in hard formations.

7) Reverse circulating and core-type. These cut a core from the formationusing shoe with hardfaced teeth and then retain it with folding

fingers. Reverse circulating action is created by dropping a balldown the string and seating in position on the valve seat. Flow isthen diverted to create a reverse circulating action to carry junk intothe tool.

5.7.6 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 fishfree or to release the overshot. Primarily used for downholecompensation in place of surface compensator.

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

4. Fishing magnets. Powerful, permanent magnets with passageways for

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5.7.7 Summary

It is important to approach a fishing problem in a thoughtful and controlledmanner. Time spent thinking about possible problems that could beencountered will be time well spent. A hasty, ill conceived approach may makean 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 thetest:

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 surfacetesting equipment. Fire extinguishers should be placed close to thesurface equipment.

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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 anyplugged 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 onshore just prior to job and witnessed by Certifying Authorities.

4. The wireline lubricator and its assembly on the surface test tree should bechecked and pressure tested.

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

6. The burner ignition system should be checked.

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

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

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Well test equipment to be tested as per Well Test Programme andWell Testing Company Procedures to satisfy requirements of CertifyingAuthority. All pressure testing to be carried out as per the Companypressure testing safety procedures. Test all remote shutdown systemsensure 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 ofhydrocarbons. Ensure that hoses are spotted where additional coolingmight be required.

Check that subsea test tree and slick joint dimensions are correct forwellhead/BOP space-out. This may be confirmed using a DummyRun (Ref. Well Test Programme).

Meeting to be held with OIM, Senior Toolpusher, Operators Drilling

Supervisor, Well Test Supervisor and all parties concerned with thetesting to discuss, draft and implement any specific proceduresrequired.

In areas where there may be H2S at surface during flow periods, thenensure that equipment and contingency procedure are ready. Carry outtraining and drills to ensure proper response by emergency teams andnon essential personnel mustering.

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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 (particularlywhen picking up from mousehole) and then allow the tubing to slipdown once it has swung to vertical while Floorman is removing pin endprotector.

11. Well test/well kill.

12. Ensure that installation cooling is running before flaring hydrocarbons.Check that all equipment is protected from water damage (whereapplicable) and close off any intakes or exhausts to prevent wateringress.

13. During flaring operations, carry out regular inspections of likely Hot Spotsand apply additional cooling where it may be required, e.g. rig columns,inside box girders, riser tensioners and DDM hydraulic pipework onderrick leg.

14. Ensure that the well is closed in with 2 barriers when rigging up wirelineequipment (BOPs and lubricator). Pressure test same as per Well TestProgramme. Use glycol/water mix for flushing surface equipment tominimise problems due to hydrates.

15. Observe safe working practices for manriding winches when

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5. Take care when breaking DST downhole tools as sections may contain

fluids at bottom hole pressures, ensure that Service Engineers are onthe rig floor to supervise these operations. Ensure slips are set andhole 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. Removeprotectors, clean and inspect threads (this will usually be done byInspection Engineer).Drift tubing.

Lay out, measure and prepare completion tools.

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

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

Check all handling equipment required:

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

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

Control running speed to prevent inadvertent setting of packers.

5.9.3 Commissioning And Wireline Work

1. Observe safety procedures required when pulling BOPs and installing xmastree e.g. moving rig off location etc. (Ref. Well CompletionProgramme/Operators Procedures).

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

3. Observe the Company Safe Working with Man Riding Winch Procedureswhen installing/removing wireline BOPs and lubricator on surfaceflowtree.

4. Ensure surface equipment, wireline riser, wireline lubricator and BOPs areflushed to remove hydrocarbons before breaking and rigging downequipment.

5. Restrict Crane Operations during wireline work to avoid collision between

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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 withsafety wires/chains. Observe pressure testing procedures when testingsame.

7. Restrict crane operations when coil tubing in use to avoid collision betweenload and tubing. Urgent lifts close to the tubing should only be carriedout following discussion between: Senior Toolpusher, OperatorsDrilling and Stimulation Supervisors, Coil Tubing Supervisor and CraneOperator. This type of operation should only be carried out when coiltubing is out of the hole and NOT under pressure.

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

9. Hold safety meeting with Senior Toolpusher, Operators Supervisor(s),Drill Crew, Deck Crew and Stimulation Engineers before acidisingoperations. Ensure that contingency plans prepared for acid spill/leakat high pressure lines and check that communication systems are inplace for rapid shutdown of pumping operations. It would be beneficialto have plasticised sheet posted in Dog House for valve status to beupdated by Driller, especially for workovers.

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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 theplug to be set.

Circulate and condition mud until in balance.

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

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

If open hole below the deepest casing, the top of the plug across the casingshoe 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 casingshoe when the condition of the formation makes cementing across the shoedifficult, these will normally be set on wireline. Pressure test plug against shearrams once wireline is out of the hole.

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Perforating For Squeezing/Checking For Pressure

1. Perforating to be carried out according to the abandonment programme.2. 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 throughchoke manifold.

5.10.3 Abandonment

Temporary Abandonment

In the case of temporary abandonment there are certain additionalrequirements.

1. A mechanical bridge plug shall be placed in the smallest string of casing

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Mechanical Cutting

1. Run in hole with the casing cutter to the desired depth. Land out marineswivel in w/head with 10,000 lbs.

2. 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 thePGB by using the 20" casing spear. Winch operators should bepositioned as required to retrieve guidelines.

Explosive Cutting

PRECAUTIONS WHEN USING EXPLOSIVES FOR CASING CUTTING ANDWELLHEAD RECOVERY.

The explosive cutting container must be completely filled each time to givean instantaneous explosion and, therefore, it is difficult to vary thecharge beyond the specified value i.e. 27 lbs and 35 lbs equivalent

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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 therig should be subtracted from the water depth.

2. The explosive cuttings charge must be placed at least 15 ft, and as much as20 ft below the mud line, to reduce as much as possible the pressureon 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 thewellhead.

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

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 atwhich the mud completely surrounds the wellhead/casing. In caseswhere cratering has occurred or the sea bed is eroded away, the mudline is considered to be at the wellhead.

9. The heave of the rig must be considered and allowance made to ensure

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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 beperformed 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 chargescan then be read from the graph.

Should circumstances arise that are not covered by the above guidancenotes, the shore base should be consulted.

In any event, the Rig Manager must be contacted as soon as it is knownthat explosive cutting is planned.

Retrieving guide bases using explosives only to be performed whenmechanical cutting has failed or where hard formations have causedproblems with retrieval after mechanical cutting.

If cutting by explosives, consider the effects of underwater explosion on rigstructure and equipment such as hydrophones etc.

Sea Bed Inspection

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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 ofcases, the responsibility for planning the well path and monitoring the progressof the same during drilling will be with the Operator and theOperators Representatives offshore and onshore. It may however be the casethat the well is being drilled as an Integrated Service package with alldirectional drilling services being provided by or subcontracted by the Company.In this case, greater responsibility will be placed on the Company drillingpersonnel. The following are guidelines to assist in development of well specific

safety procedures during well planning and implementation.

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5.11.2 Directional Drilling Pre-Spud Meeting

Topics To Be Discussed

Prior to the start of any well, the Drilling Supervisor is to conduct a pre-spudmeeting. The directional drilling plan for the well is to be discussed including thefollowing topics:1. Wells which may be approached and any planned safety plugging

programme.

2. Directional Drilling Procedures and surveying requirements that will be usedto 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).

3. Directional 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 factorsare applied to each survey in accordance with Well Programme requirements.

Directional Surveyor/MWD Operator

These personnel are to take directional surveys as required by theWell 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 calculationsusing 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 ascarried out by the Directional Driller and Surveyors.

Radius Of Error

The directional drilling safety limits discussed in this section are based on thedefinition of a radius of error equivalent to 6 ft/1000 ft of measured depth belowthe 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 ofwells and protect the installation during the drilling operations. Conflict between

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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 comparedto the allowable minimum well separation for the current drilled depth.Guidelines for determining acceptable well separation distances are given in thefollowing 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 deviationfrom these guidelines must be approved by the installation Rig Manager.

Depth Distance of Approach

Required Precautions

above 2000 ftMD BSB

> 3 RE No special precautions other thanplanned directional survey frequencyand distance of approach calculations.

2 RE to 3 RE Evaluate critical wells (particularlyproducing wells). Plug/depressurisewells as required. Follow approvedplan and proceed with extremecaution.

< 2 RE Stop drilling. Inform OIMs on the

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5.11.5 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 shouldbe examined to see if it should be temporarily plugged prior to drilling throughthe interval of close approach. Factors to consider when examining the possibleintersection of an existing well by another include:

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).

5.11.6 Determination Of Whether To Temporarily Plug Endangered Wells Below2000 ft MD BSB

Endangered wells are to be temporarily plugged when the centre to centredistance (in 3-dimensions) between the object well and the planned or actualwell is expected to be 3 RE or less. A well that will be approached within 3 REshould 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 ofclosest approach in the drilling (subject) well. However in certain cases themeasured depth of the object well (the well being approached by the drillingwell) 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 isto be modified slightly to account for the greater degree of borehole uncertaintyin the object well. Under these circumstances, the 2 RE calculation is to be

performed as follows:

1. Calculate the radius of error in the drilling well at the depth of closestapproach. This number is identified as RES.

2. Calculate the radius of error in the object well at the depth of closestapproach. This number is identified as REo.

3. Calculate the 2 RE distance as follows:

4. RE = RES + REo.

5.11.9 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:

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7.0 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)

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Page : 68 of 80Rev No : 2Date : 12.03.99Doc No : DOP 202 Enc 1

Enclosure No 1

BOTTOM HOLE ASSEMBLY SHEET

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Routine Drilling OperationsPage : 69 of 80Rev No : 2Date : 12.03.99Doc No : DOP 202 Enc 1

Bottom Hole Assembly

FOR: ______________ WELL NO: _____________OPERATOR: ________DATE: _____

QTY DESCRIPTION THREADS LENGTH CUMULATIVELENGTH

OD ID FN FT SERNO

REMARKS

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Enclosure No 2

TRIP SHEET

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Routine Drilling OperationsPage : 71 of 80Rev No : 2Date : 12.03.99Doc No : DOP 202 Enc 2

Trip Sheet

DATE:..

WELL NO:.. ACTIVE PIT VOLUME:.. START TRIP TIME:

DEPTH:.. START OF TRIP:

END OF TRIP:. END TRIP TIME:

5DP

STDNOS

TRIPTANKRDNG

ACTVOL

USEDBBLS

THEOVOL

USEDDRY

5HWPD STD

NOSTRIPTANKRDNG

ACTVOL USED

THEO VOLUSED DRY

6.5DCSTDNO

TRIPTANKRDNG

ACTVOL

USED

THEOVOL

USEDDRY

0 0 0 0

5 1 1

10 2 2

15 3 3

20 4 4

25 5 5

30 6 6

35 7 7

40 8 8

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Enclosure No 3

CHECKLIST FOR 30 CASING

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CHECK LIST FOR 30 CASING

ITEM LOCATION CHECKEDT.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 TuggersT.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

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Enclosure No 4

CHECKLIST FOR 20 CASING

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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

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Enclosure No 5

CHECKLIST FOR 13-3/8 CASING

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CHECK LIST FOR 13-3/8 CASINGPooh Last Bit - Collars To Be Accessible For Setting S/Assy. After Csg Job

Cut And Slip Drilling Line If Required -Pull 18In - 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 -

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DOP 202 - Rev 2

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