DOP 204 - Rev 4

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Drilling ProblemsPage : 1 of 29Rev No : 4Date : 12.03.99Doc No : DOP 204

Document No. Document Title

DOP 204 Drilling Problems

TABLE OF CONTENTS

1.0 PURPOSE............................................................................................................. 21.1 SCOPE............................................................................................................. 21.2 RESPONSIBILITIES...................................................................................... 2

3.1 Senior Toolpusher.................................................................................................. 2

4.0 DEFINITIONS....................................................................................................24.1 PROCEDURE.................................................................................................. 2

4.2 Drilling Problems....................................................................................................... 24.3 Lost Circulation......................................................................................................... 54.4 Drill String Sticking.................................................................................................... 74.5 Freeing Stuck Pipe.................................................................................................. 124.6 Bad Weather Operations........................................................................................ 184.7 Sour Gas Wells....................................................................................................... 224.8 Shallow Gas............................................................................................................ 25

4.9 REFERENCES............................................................................................... 294.10 ENCLOSURES............................................................................................ 29

RevNo

Date Preparedby:

Verified by: Approved by:QA and Safety

Managers

Reason for Revision

3 16.07.97 AMO WVE AMO As Per Revision RequestNo. 009

4 12.03.99 IMI / LVA ICO AJE / BNO As per Procedural ReviewScheme

G:\Management Library\Drilling Operations Manual\DOP204

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1.0 PURPOSE

The purpose of this procedure is to describe and give guidance on the most

common problems that can arise during a Drilling Operation.

2.0 SCOPE

This procedure applies to all of Stena Drillings units.

3.0 RESPONSIBILITIES

3.1 Senior Toolpusher

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

4.0 DEFINITIONS & ABBREVIATIONS

Ref. DOP 208.

5.0 PROCEDURE

5.1 Drilling Problems

5.1.1 Hole Instability

Hole problems develop over a period of time and careful observation of certaintrends can give advance warning that conditions are deteriorating. Remedialaction taken early enough can avoid the drill string becoming stuck and possibleloss of the well. The essential parameters to monitor are drag, torque, characterof cuttings at shakers and pump pressure/stroke relationships. A record ofthese parameters is kept on the Drillers drilling parameters log (Ref. DOP202Section 3 Enclosures).

5.1.2 Drag

This should be recorded at each connection. It should also be recorded duringeach trip so as to be able to compare with drag on previous trip. In directionalwells, drag will of course increase with depth and angle but at any given pointthe drag should remain the same on successive trips.


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5.1.3 Torque

Changes in this should be compared with drag trends. Fluctuating torque maybe the result of formation change but consistent high torque should be viewed

with suspicion.

5.1.4 Cavings

Changes in shape and character of cuttings at the shakers may be an indicationof formation changes and pressure.

5.1.5 Pressure

An increase in pump pressure with the same strokes (assuming it is not due to ablocked nozzle) could be due to a bridging formation, balled-up BHA or a simplehole cleaning problem.

We shall consider several forms of wellbore instability with indicators andremedial procedures.

5.1.6 Shale Problems

Indicators

1. Fill on connections and after trip.

2. Increasing pump pressure.

3. Excessive cavings coming across shaker screens.

4. Torque and drag on connections and trips.

Mechanical Conditions Contributing to Shale Problems (Erosion due toturbulence shown by mixed sizes and shapes of cavings).

Pressure differential shown by narrow pointed shale splinters and gas cut mud(gas bearing shales).

Pipe whip shown by numerous small mixed shapes of various formation types.

Swab/surge pressures shown by large quantities of fill or debris and lostcirculation.

Chemical conditions/shale hydration. This will result in two distinctly differentproblems:

1. Swelling/expansion of the clays due to water intake from the drillingmud.

2. Dispersion - the disintegration of a shale body due to water contact.

Remedial Procedures

1. Use inhibitive muds to reduce interaction with water phase.


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2. Use chemical additives to help seal fractures.

3. Reduce turbulent erosion by changing mud properties or reducing

annular velocities.

Pressure differential problems can be solved by raising mud weight to balanceformation pressure.

Change weight distribution to bring drill pipe into tension to cancel pipe whip.

Pull/run pipe more slowly or condition mud to reduce yield point and gelstrengths to counter problems due to swab and surge pressures.

5.1.7 Unconsolidated Formations

These consist of sands, gravels etc. which are not bound together'.

Indicators

1. Rough drilling.

2. Fill and excessive torque and drag on connections and trips.

3. Frequent Packing-off and bridges at specific depths.

4. Large amounts of cavings across shakers following trips.

5. Continual re-drilling of footage.

6. Mud losses.

Procedures

Increase viscosity and gel strengths to improve hole cleaning andsuspension.

1. If possible increase mud weight.

2. To control losses use viscous pills with fibrous LCM material.

3. Consider erosion effects and annular velocities in problem zone.

4. Squeeze cement into the zone.

5. Case off the zone.


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5.1.8 Evaporate Deposits

These are salt formations and may occur as stringers and massive salt sections.

Problems associated with evaporate deposits:

Excessive washouts may cause:

1. Reduced hole cleaning.

2. Undermining (causing caving in).

3. Chemical contamination of mud due to dissolved salts.

4. Unwanted side-tracking of the hole may occur.

Indicators

1. Increasing chloride concentrations without volume increases.

2. Increasing plastic viscosity and hardness.

3. Decreasing amounts of cuttings T shakers due to a continuallyenlarging washout.

4. Flocculation of fresh water muds.

Remedial Procedures

1. Convert to an inhibitive mud system, e.g. suitable oil base mud orsaturated salt system.

2. Increase the viscosity and gel strengths to improve hole cleaning andsuspension.

3. Drill evaporate formations and then case them off.

5.2 Lost Circulation

This is the result of pressure exerted on the formation exceeding the formationpressure and openings in the formation being bigger than the largest particles inthe drilling mud.

It is important to identify and contain losses as there is always the possibility thata reduction in the mud hydrostatic will allow another formation's fluid to flow intothe well.

Circulation losses can be considered in the 3 categories below, each in turnshowing increasing severity of losses.


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5.2.1 Seepage Losses

These are continuous and gradual losses which occur in highly permeableformations and the rate of mud loss is dependent upon the degree of

permeability. Sands are normally associated with this type of mud loss but itmay also be due to pea gravel, shell beds or reef deposits.

Remedial Procedures are:

Treat system with fine lost circulation materials.

Increase mud viscosity.

5.2.2Partial Losses

These are severe but not complete loss of returns. They develop slowlyand increase with penetration of the loss zone. They are associated withhighly porous formations (shell and gravel beds and unconsolidated zones)OR fractured formations.

Natural fractures may be indicated when losses occur during or immediatelyafter rough drilling or sudden formation change. Induced fractures areindicated where losses occur while tripping, breaking circulation or raisingmud weight. This is caused by exceeding the fracture gradient of exposedformations dynamically (ECD or swab/surge pressures) or statically (muddensity).

5.2.3Remedial Procedures Are:

Treat mud system with LCM of various sizes and shapes. Mixtures of

different sizes and shapes are often quite effective.

When losses are severe, mix a pill containing 30 to 40lbs/bbl of various

LCM types, spot this opposite the loss zone, pull back into the casingand wait 6 to 8 hours.

Squeeze the zone with a high filtration slurry. When applying a high

filtration slurry, squeeze slowly at to 1 bbl / min with pressure notexceeding 50 to 100psi. Final squeeze pressure should not exceed 0.1

psi / ft of depth.

5.2.4Total Loss Of Returns

These occur in cavernous and vugular formations and may be accompaniedwith bit drop in cavernous formations. These losses are usually predictableat certain depths in areas with significant drilling history. Formations whichtypically exhibit this type of loss are limestone reefs, dolomite and otherformations with fissures.

Remedial Procedures Are:


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Drill blind without returns until loss zone can be cased off. This can bedangerous as large cavities may be created or the well may kick with noeasy means of control.Cement loss zone with: neat or bentonite cement slurries for densities

of 14.5 to 15.5lbs/gall:

Squeeze the loss zone with soft plugs, oil-bentonite - cement, oil-bentonite (gunk squeeze) slurry.

Drill with air, stiff foam or aerated mud.

In all cases of lost circulation, it is important to maintain control of thewell (Ref. Well Control Manual WCO 200). The above remedialprocedures are for guidance only. Listen to the people on the spot,Mud Engineer and Geologist and form a plan of action to deal with theproblem. The Mud Engineer has the training for preparing specialist

pills so use that knowledge.

It is better to avoid lost circulation problems by proper preventativeprocedures than to cure it after the formation has been broken down.

Preventive Measures

Use the minimum mud weight allowable by exposed formation pressures.

Plan to set casing at a suitable depth to protect low or sub-normally pressuredformations from high mud weights.

Minimise swab and surge pressures by proper mud treatment and controlling tripspeeds.

Minimise pressures when breaking circulation on critical wells. Utilise stand-pipechoke (where fitted) to break circulation with a slow gradual increase inpressure. Upward movement and rotation of the drill string will also helpreduce pressures.

Minimise annular restrictions by:

1. Using inhibitive muds to prevent balling of bit and drill collars.

2. Control drilling rate to minimise loading of annulus with cuttings.

5.3 Drill String Sticking

The most common causes of sticking problems are:

Differential sticking (wall sticking).

Key seating.

Hole instability.

Insufficient hole cleaning and resultant cuttings accumulation.


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Running into a bridge, tight spot or undergauge hole. Bottom hole

assembly changes.

Junk in the hole or collapsed casing.

Plastic salts.

Drilling or reaming without the mud pump.

Most sticking problems develop over a period of time and it is important toobserve trends in drag, torque and pump pressure/stroke relationships,(Ref. Section 5.1) to identify and conditions are deteriorating.

5.3.1Differential Sticking

This problem is caused by excessive differences between the mudhydrostatic and formation pressures. The pipe is literally pushed againstthe side of the hole. This condition is usually associated with a thick andspongy wall cake.

The symptoms of differential sticking are easily recognised and should notbe confused with other types of sticking. These are:

Severe overpull each time the pipe is stopped.

If the pipe has become stuck whilst stationary and normal circulation is

possible without any pressure increase.

Factors Affecting Differential Sticking

The following factors affect the possibility of getting wall-stuck.

1. Permeable zone, with spongy filter cake.

2. Hydrostatic / formation pressure differential.

3. Type and concentration of solids.

4. Lubricating properties of the mud.

5. Collar and pipe size in relation to hole size.

6. Hole deviation.

Precautions Against Getting Wall-Stuck

There are several precautions we can take to minimise the chances of becomingwall-stuck:

1. Keep pipe moving and minimise time spent with pipe stopped againstthe side of the hole.


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2. Keep the mud weight and solids content as low as possible.

3. Reduce the contact area between collars and filter cake by using spiralcollars and string stabilisers.

4. Reduce the friction factor with oil, emulsifiers, detergents or lubricants.

5. Control filtration rates to maintain a thin, slice wall-cake.

5.3.2 Key Seating

A keyseat is formed over a period of time by the drill pipe wearing into the lowside of a dog leg. The large diameter of the drill collars is then unable to passfreely through this point. Indications of a keyseat forming are:

Common tight spot on successive trips.

Associated with increasing overpull at same spot.

Dog legs should be thoroughly reamed as soon as possible after they areformed and found from directional surveys. If this is not fully effective, thenconsider running a keyseat wiper or string reamer in the drill pipe to wipethe dog leg. The reamer must be larger than the drill pipe tool joint andsmaller than the collars.

5.3.3Insufficient Hole Cleaning

Indicators of Hole Cleaning Problems

If cuttings are not removed from the well, they will settle around the drillstring causing the hole to pack off and the string to become stuck. Theproblem is exacerbated in over-gauge sections where annular velocitiesare reduced. Cuttings will build up and eventually slump into the hole.

High angle wells are more difficult to clean then vertical ones, becauseof the tendency of drilled solids to fall to the low side of the hole. In avertical well, provided the circulation rate is higher than the slip velocityof the cuttings, then the hole will be cleaned. In highly deviated wells,the cuttings have only a short distance to fall, before they lie on the low

side of the hole. Beds of cuttings will be formed which are not easilyremoved. Problems can be caused when tripping out of the hole, asthe BHA will be pulled into the cuttings beds. The cuttings will bedragged up in front of the top collar or stabiliser until the hole packs offor the pipe is pulled tightly into a plug of cuttings.

Indicators Of Hole Cleaning Problems are:

1. Excessive overpull on connections and trips.

2. Reduced overpull when pumping.

3. Excessive fill after trips.5.3.4 Precautions To Minimise Hole Cleaning Problems


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There are several precautions we can take to minimise hole cleaning problems:

Do not permit the flow rate to drop below the minimum required to clean the

hole. If a mud pump goes down, then stop drilling until it is repaired.Trip back into the shoe if the delay is going to be a long one. Do notdrill ahead, expecting to clean the hole at a later stage. It may be toolate.

Modify viscositys and gel strengths to improve fluid flow properties.

Prior to starting a trip, the hole should be circulated until it is as clean as

practically possible.

A minimum circulating time should be pre-determined, but a trip should not

be started if there are still significant quantities of cuttings coming over theshakers at that time. It may be beneficial to rotate and reciprocate the stringwhile circulating in inclined wells as the movement assists hole cleaning bydisturbing cuttings beds. There are situations where circulation alone couldbe maintained for days without the hole being completely cleaned. Thismay often be the case with cuttings beds or wells with severe over-gaugesections.

Special procedures may need to be used. Solutions such as pumping andback-reaming out or the use of under-gauge stabilisers in the drill pipe todisturb cuttings beds have been used with success.

5.3.5Under-Gauge Hole And BHA Changes

These will lead to the chances of the string becoming stuck during a trip inthe hole. It will suffice to mention appropriate precautions to take tominimise the chances of the string becoming stuck:

Always gauge bits and stabilisers before and after every trip. Note and

report equipment going under-gauge and replace same as required.

Careful examination of torque records may show the point at which the bit

gauge became worn. This may enable planning a depth at which toexpect under-gauge hole and the need to ream.

Extreme caution must be taken when tripping into a hole which is thought to

be under-gauge. It is better to err on the safe side and ream than toforce the new bit into under-gauge hole and damage it or worse get thestring stuck.

5.3.6Junk In The Hole Or Collapsed Casing

Junk in the hole will be shown by erratic drag and torque readings. Theonly course of action is to work the string up and down, rotate if possibleand attempt to force the junk clear. Friction reducers probably will not help.


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Collapsed casing will result in sudden resistance, usually spotted on tripsout. To free the string, it will be necessary to work it down but the long termsolution requires specialist tools.

5.3.7Plastic Salts

In this case, formations extrude over time and invade the well bore to stickthe pipe. In the case of a well being drilled in a known area, then certainsteps can be taken to minimise the problems created by these. Eccentricbits have been used successfully. These bits drill a hole which is greaterthan its nominaldiameter, typically by 1/8. With the larger hole, the salthas to move further, before it stick the pipe. This gives more time to drill thesection before a stuck pipe problem will occur. These bits have been usedeffectively in the Southern North Sea.

5.3.8Staying Out Of Trouble

Many instances of stuck pipe could be avoided by paying close attention tochanging parameters and observing good drilling practices.

Maintaining good communications between Driller, Mud Engineer, MudLoggers and Geologist will help identify trends and signs of impendingproblems and their type.

Circulate and clean up the hole before tripping out.

Be alert when tripping through open hole, the problem formation may betime dependent and so dont assume that since there were no problems onthe last trip out that its clear this time.

When tripping through tight hole, be patient and steady. Working through atight spot may be more effective than attempting to jar through. You canjar yourself into trouble more quickly than you can jar yourself out of it.

When working through a tight spot, check frequently that the string will goback down. Monitor trip tank to ensure that swabbing is not occurring. It isgood practice to keep the overpull used less than the BHA weight. This willensure that it should always be possible to work the string down. It ispossible to make good progress through tight spots by wiping downthrough the length of a stand occasionally. This may help prevent the buildup of cuttings/cavings on the collars and stabilisers.

On the first signs of tight hole, the Toolpusher and Operators DrillingSupervisor should be alerted (assuming that they are not already on the rigfloor).

At any stage, if little progress is being made through the tight spot, then theDDM/Topdrive should be made up and used to pump out, rotate andgenerally help clear the BHA. If there is swabbing, then it will be necessaryto pump out to ensure proper mud displacement for steel removed.

Any tight spots and bridges should be reamed carefully on the trip in.Monitor torque and pump pressure closely and ensure string is free to workup. Keep the problem below the bit.


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When reaming sloughing shales, there is the danger of loading the annulasif penetration rates are too high. Consider the need to get the hole cleanand if necessary periodically wash back a single or stand to give time to

clean the hole.

Do not wait until the string is stuck before calculating the maximum overpull.This should be known at all times and a suitable safety margin considered(e.g. 80% of maximum load specified in IADC Manual).

When running directional surveys etc. where it is necessary to have thestring stopped for an appreciable length of time without circulation, try andposition the pipe to be able to move down and dislodge any loose materialthat may have accumulated above the collars and stabilisers.

When circulating, avoid rotating pipe in one place off bottom as this can

create a washed-out area in soft formation and it will also increase wear indog legs leading to keyseats. Try and reciprocate pipe over as great adistance as possible. Varying speeds will help clean up BHAs before tripout of hole.

5.4 Freeing Stuck Pipe

The first actions taken when the drill string becomes stuck have the greatestchances of success. It is important to make the correct responseimmediately. Points to consider are:

If the pipe was moving immediately prior to becoming stuck, always try to

move in the opposite direction.

Use the jars as soon as possible, jarring in the opposite direction to the pipe

movement before becoming stuck (know the maximum limits of the jarin advance).

Work pipe to the limits specified by Toolpusher.

Make up DDM/Topdrive as soon as possible after initial attempts to jar free.

Establish circulation, this will help cool hydraulic jars and maximiseworking time of same. Working the string with right hand torque will

now be possible as well,

If differential sticking is suspected and the pipe cannot be pulled free, work

in right hand torque and slump the pipe. If the bit is on bottom,continue working the pipe by pulling up to the maximum and by jarring(ensure jar has tripped before pulling above its maximum capacity).

Have the chemicals and mud pits ready to make up a pill.


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During the earliest stages of trying to free the pipe, decide what caused it to

become stuck. This may well be obvious from the conditions whichhave existed previously. It is important to take this diagnostic processseriously as an incorrect identification of the problem, lowers the

chance of successfully freeing the pipe.

The following examples are the types of questions which should beconsidered before determining a course of action:

Is there a potential well control problem? This could occur if hydrostatic

head is reduces to free differentially stuck string, for example.

Safety considerations?

Equipment available on the rig.

Additional equipment/chemicals required?

Free point tools, back-off tools.

Pipe freeing chemicals.

Acids.

Any information available from past wells drilled in the field?

Formation at stuck point:

1. Sloughing shale.

2. Plastic salt.

3. Limestone or chalk.

5.4.1 General Safety

Operations to free stuck pipe will stress equipment with greater and morefrequent load cycling than day to day drilling operations. There are several

points to consider during these operations:

Minimise risk to personnel by keeping rig floor and derrick areas clear.

Ensure personnel are properly briefed and if necessary rope off areasand make PA announcements to keep non-essential personnel clear ofdangerous areas. Keep personnel required to a minimum.

Hoisting equipment, draw-works, blocks, DDM/Topdrive, elevators and

drilling line will be subject to above normal stress. Pay particular attentionto:

1. Overheating of brakes and build up of cooling water temperatures.

Schedule rest breaks as required.2. Maintain correct adjustment of brakes to compensate for wear and tear.


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3. Regular inspection of blocks, DDM/Topdrive, derrick structure andpipehandling equipment of signs of bolts working loose. This canbe done during rest periods, (Ref. Manufacturers Operating

Manuals).

4. It is recommended that DDM/Topdrive is made up to the string forworking right hand torque into the string. This gives the greatestamount of control and flexibility in working the string up and downwith torque held in.

5. Where it should be necessary to use slips to turn the pipe, tie thehandles to prevent slips being thrown around rig floor area if thestring should lift. Ensure that torque has been released from stringand string picked up off the slips before sending personnel to pullthe slips.

6. In the event of string parting or pulling free and causingblocks/DDM/Topdrive to jump, ensure that crown sheaves areinspected before continuing operations. This is to ensure thatdrilling line has not jumped off a sheave(s). It is vitally important toinspect the drilling line for damage.

7. It is safer to slip and cut off the damaged line than to risk a parted line,with its catastrophic consequences.

8. Inspect the drilling line at regular intervals, particularly in the areas ofgreatest wear. (Ref. Section 1.4).

9. Be alert for any potential well control problems.

10. Effects on maximum pull on pipe when torque is appliedsimultaneously, (Ref. Formulae Section 8).

5.4.2 Stuck Pipe In Limestone Or Chalk

These formations may be dissolved using an inhibited hydrochloric acid pillspotted around the stuck point. If the pill is going to be successful, then freeingwill take place quickly as the formation is dissolved by the acid. The maximumtime for a pill to work is 2 hours.

Ideally the pill should be spotted with a large water spacer ahead and behind it,as the acid can cause severe mud problems. It is essential to include wellcontrol considerations in determining spacer size.

It is important to consider the effects of the ac id corroding high strength steels,tubulars should be inspected after the pipe is freed. Safety procedures must befollowed when handling acids.


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5.4.3 Plastic Salts

Stuck pipe in a salt section can usually be freed using a fresh water pill, spottedaround the stuck point.

The stuck point will usually be in the BHA and typically a fresh water pill, largeenough to spot across the BHA with extra volume (approximately 20bbls) left inthe string could be pumped. With oil based muds, a spacer should be pumpedahead of the pill containing water and detergent. After the pill is spotted,maximum pull should be kept on the pipe so that it will come free when sufficientsalt has dissolved. Periodically pump a couple of barrels to move more freshwater into hole. This should free the pipe within 2 hours. If no success, use asecond pill where possible.

Well control must be preserved when using unweighted spacers.

5.4.4 Keyseat Stuck

Attempt to work the string down, it is probable that the jars may be ineffectual asthe string will be stuck above them. This is of course dependent on type andplacement of jars. Working in right hand torque and slumping the string may getthe string free and then it may be possible to backream and pull the string outpast the obstruction.

The bowen surface jar is a tool designed to be installed at surface to deliver aheavy downward blow against a stuck string. This tool is unusual in that in orderto strike downward blows, the operator pulls upward against the tool. Thetripping force of the surface jar is adjustable, but it should be set so that the pullnecessary to trip it does not exceed the weight of the drill pipe between thesurface and the stuck point. This is necessary to avoid pulling a stuck drill collarfurther into the keyseat.

Failure to free the string may mean that the string will need to be backed abovethe stuck point. A fishing string with up and down jars, string reamer, drill collarscould then be run. Once the fish is engaged, downward jarring with rotation andcirculation should free the string and then the reamer could be worked throughthe keyseat to clear a path to pull the string out of the hole.

5.4.5 Differentially Stuck

There are several techniques available to free differentially stuck pipe, these willhave a better chance of success with the string in compression.

Spot oil containing surfactant around the drill collars, allow this to soak.

This works by breaking up the wall cake.

Reduce mud hydrostatic by circulating and cutting back system mud weight.

Reduce mud hydrostatic using a U-tube method.

Release overbalance using a DST packer.

5.4.6Surfactant Pills


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These are made up of oil/diesel mixed with surfactant chemicals (pipe laxand suchlike) spotted around the drill collars to break down the filter cake.Use twice the drill collar annular volume and displace one volume aroundthe collars. Pump 1-2bbls/hr to compensate for migration. Once the pill is

in place, the string needs to be worked and it will probably be more effectiveto work in right hand torque and work the string down in compression. Thistechnique may take up to 8 hours to free the pipe, so be patient. Wellcontrol must be maintained at all times. The effects of the unweighted oilpill must be considered. As the sticking problem is due to an excessiveoverbalance, it will be helpful but caution must be taken to ensure pillvolumes are not excessive.

5.4.7 Reducing Hydrostatic

This method is to circulate the mud system while cutting back the mudweight. The minimum mud weight must be predetermined and the well

must be monitored closely for flow. This method has severaldisadvantages:

It is slow and the longer pipe is differentially stuck, the greater the chances

of it becoming mechanically stuck.

It may be difficult to spot a slow influx of formation fluids as the active

volume is being increased continuously. Therefore extra caution isrequired.

On floating rigs, depending on water depth and mud weight, the hydrostatic

can be reduced quickly and safely be displacing the choke line to baseoil or water. The well is then shut in using the annular preventer(minimum operating pressure) and the choke line opened, so reducethe overbalance. Any influx can be easily spotted and the well madesafe immediately. The well would be killed by closing the choke lineand opening the annular.

If the pipe is not freed on the first attempt, then an equivalent mud weight

can be calculated from the known, safe hydrostatic. The mud weightcan be cut and the process repeated. This can be done until the pipe isfree or the minimum hydrostatic reached.

5.4.8DST Packer

This method relieves the overbalance immediately and it might be tried afterthe previous methods have failed. A back-off is made over the stuck pointand a packer run with either open ended drill pipe or an overshot below it.Where to set the packer will be determined by the open hole conditionabove the fish, but it may be necessary to space out and set the packer inthe casing. This is a specialised procedure and details would be suppliedby the Fishing/Packer Engineer.


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5.4.9Free Point And Back-Off

Determining Stuck Point

When drill strings become stuck and other methods are unable to free them, itbecomes necessary to determine the stuck point and then recover the freepipe above that point. This may be to run fishing equipment (washoverpipe, jars and accelerators) or to minimise equipment losses beforeplugging back and side-tracking. There are two methods for estimating thedepth at which the string is stuck:

1. Locating the free point with a free point indicating tool run on electricline.

2. Measuring the pipe stretch under tension and calculating the length offree pipe. This method has certain limitations and would not beaccurate enough for determining the optimum back-off point.This would be determined using the free point indicating tool.

An example and procedures for this method, (Ref. DOP 205).

Running Free Point Indicating Tools (FPIT)

The following below, considers procedures and general guidelines for runningFree Point Indicating and String Shot Tools. (FPIT) (Ref. Rig Specific WorkMethodsInstruction Manual for more detailed information).

Constant communication is required between Driller and Logging Unit.

It is recommended that the logging cable is run through the DDM/Topdrive asthis offers several distinct advantages and this is the safer method offeringfewer hazards to personnel.

1. Internal BOPs are available to shut in the string if it is necessary toclose the well in. Ensure that wire cutters are on the rig floor whenthe logging cable is in the drill string.

2. It is safer (and easier) to work in right hand torque for free pointmeasurements and left hand torque for string back-off than using slips

and back-up tongs.

The procedures to run the cable will depend on the situation and equipment athand, (Ref. Manufacturers Operating Manual for running wirelines throughDDM/Topdrives).

Should it be necessary to use slips and tongs to work torque into the string, it isrecommended to (where possible):

1. Rig up long safety and back-up lines on the tongs to allow high verticalmovement. Make sure that tong and slip dies are in good condition.Check that tongs are of correct rating for torques anticipated.

2. Use a joint of HWDP on top of the string, this will resist crushing damagefrom the back-up tong.


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3. Ensure that all personnel involved in working with the slips and tongs arefully briefed of the hazards involved and safety procedures to follow.

The jars must not be tripped whilst the FPIT are in the string.

Free point readings are taken at various depths and both tension and torque areapplied. The Logging Engineer will specify values of these to be used.

A successful back-off depends on three main things:

1. Zero or slightly positive tension at the joint to be backed off.

2. Sufficient left hand torque at the joint.

3. A sufficiently large explosive charge accurately located at the point.

Do not make the back-off in any short subs, crossovers, stabilisers etc. as it mayback-off at both connections.

Check the torsional limit of the weakest part of the drill string and beforeapplying left hand torque, work right hand torque (approximately 80% of thislimit) into the string to ensure it is tightly made up to bottom.

Set the neutral point at the back-off point. The required weight indicator readingcan be determined when running the FPI tool.

Apply left hand torque (approximately 60-80% of torque used to make up thestring). It will be necessary to work the torque downhole by reciprocating pipe.It is customary to run the back-off shot only a short distance down the pipe (300-400ft say), work in the left hand torque and then run the shot the remainingdistance. This is to avoid the logging cable being cut if there is an inadvertentback-off further up the hole.

Once the back-off has been successful, the wireline is retrieved. It is importantto make sure that the string is moved as much as possible to ensure it does notget stuck again.

5.5 Bad Weather Operations

The decision to suspend operations and wait on weather will be taken by theOIM in consultation with the Senior Toolpusher, Barge Master and OperatorsDrilling Supervisor. Guidelines for safe operating limits are given in the VesselSafety Case and respective Rig Specific ProceduresInformation/ProceduresManual.

Factors to be considered when deciding to suspend operations are:

Are maximum operating limits likely to be expected.

Safety of personnel-risk to same when working with large rig movements.

This will be the case when pulling out of the hole to get the bit insidethe casing.


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Damage to equipment-this might hinder operations and endanger the unit

(loss of well control).

Weather forecast-is the weather going to get worse? Likely effects offorecast, wind shift and effects on sea state.

Anchor tensions-dependent on location, water depth, but these might be a

deciding factor in deciding to unlatch and allow the rig to move offlocation.

Time required-do not leave it too late. Allow plenty of time to pull back

inside the casing shoe. A natural tendency for the Driller to pull tooquickly plus the effects of large rig heaves may lead to swabbing and apossible kick situation later.

5.5.1Preparations

Ensure that correct hang-off assembly is made up and stood back in thederrick before drilling next section. Check the following:

Hanger is correct for wellhead system in use.

Load rating of wear bushing is adequate for anticipated hang-off loads

(BHA plus drill pipe to suspend bit in casing as close to shoe aspossible).

Correct space-out between hanger and back-off assembly to allow a set ofpipe rams to be closed around the slick joint, and shear rams to beclosed above the back-off assembly once disconnected. This mustalso allow for checking pressure before opening the rams.

All dimensions noted in case, it is necessary to fish portions of the assembly

due to equipment failure.

Threads are cleaned and inspected on back-off sub: usually 63/8 Acme left

hand releasing thread with a 4 IF (NC50) box beneath for re-engaging the hang-off assembly. Check clearance for pin connection

to re-engage the sub. There have been problems due to the retrievingtool landing out on the Acme threads and being unable to make up tothe 4 box. If this is a problem, it may be necessary to machine asaver sub to fit.

Calculate landing string measurements required to land off and to ensure

that hang-off assembly is not inside the BOP when the string is set inthe slips. Plan so the DDM/Topdrive is made up to the string and thenthe Assembly is lowered through the BOP and landed off in one smoothoperation.

Arrange mud pits to receive riser displacement.


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Check with OIM if stability conditions will allow mud in riser to be displaced

into mud pits.

5.5.2Suspending Operations And Hanging-Off

It has been assumed that the bit is on bottom and at the time the rig is

drilling ahead when the weather conditions have deteriorated.

Circulate to clean the hole if time permits.

Pull the bit to the casing shoe PLUS the distance from the rotary table to the

wellhead. In situations when the procedures outlined above cannot befollowed, pull sufficient pipe so that when the drill string is hung off inthe wellhead, the bit will be at least 5 stands off bottom.

Pull back one joint and install a back pressure valve with an open kelly cock

below it. Run the joint back in the hole.

Remove the diverter insert packer.

Pick up hang-off assembly and make it up to the string.

Lower assembly and set slips below back-off sub. Check that left hand

connection is only chain tong tight.

Run the hang-off tool to just above the BOP stack.

Make up the DDM/Topdrive, open DSC, run and land the string off in the

wellhead. Confirm pipe figures and ensure that the tool is landed off inthe correct point.

Release running string with right hand rotation and pick up at least one

single of drill pipe.

Close pipe rams as required by BOP configuration, close with low pressure

and check fluid volume required is correct, lock rams.

Close shear rams with low pressure, and check fluid volume required is

correct. Lock rams.

Displace mud in the riser with seawater at maximum rate possible. (If not

already done whilst running hang-off tool, consideration must be givento loss of hydrostatic pressure if displacing prior to closing the rams).

Run and test subsea camera.

Pull out and stand back the landing string.

De-ballast rig to survival draft, if time permits.

Prepare to disconnect at the Lower Marine Riser Package, (LMRP).


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5.5.3Disconnecting Marine Riser

Make the following preparations for disconnecting:

Install the riser spider on the rotary table.

Install the diverter handling tool in the diverter.

Close the elevators on the handling tool.

Disengage the diverter lock down dogs and the diverter housing retainer

dogs.

Pick up the inner barrel of the slip joint about 0.6m (24).

Set the inner barrel back down, keeping the elevators on the handling tool.

Two watchmen should be posted at the moonpool.

The Driller and one man should remain on the drill floor for continuous

watch.

Prior to unlatching the LMRP the Subsea Engineer/Driller should calculate

the required riser tension necessary to achieve disconnect should that stepbe necessary. These calculations should be checked by the Toolpusherand Barge Master or OIM. The required tension will be that necessary toobtain pull equivalent to:

1. The buoyant weight of the marine riser.

2. Weight in air of rucker ring and slip joint outer bbl.

3. Additional factor for fluid in riser.

4. The lower marine riser package.

5. Plus sufficient overpull (normally sum total + 25%) so the tensioners willlift the riser clear (e.g. 5m) (16.5ft) off the stack after disconnecting

(but not so much as will create such momentum as to causedamage when the tensioners bottom out, although anti-slingshotvalves should activate before damage would occur).

6. Use only one or two air bottles on each pair of tensioners whendisconnecting. Isolate the others.

Disconnect marine riser.


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5.6 Sour Gas Wells

General guidance on detection and breathing apparatus are given in the SafetyManual, (Ref. SAF 200), characteristics and hazards are also shown in this

section.

It is essential when drilling operations are planned in areas where there is thechance of penetrating formations containing sour crude/H2S that thoroughplanning is carried out to:

Minimise risk of exposure to personnel.

Ensure integrity of drill string, casing and BOP equipment.

5.6.1H2S Plans

Plans should consider the following elements:

Sufficient emergency escape breathing apparatus on the rig for all

personnel on board the rig (usually in the cabins). Spare sets to belocated at the temporary safe refuge.

Sufficient working duration breathing apparatus to be available to permit the

well to be made secure in the event of a sudden unexpected release of H2S.

Recommended minimum quantities:

1. Drill Floor - 6 units

2. Control Room - 2 units

3. Toolpushers Office - 2 units

4. Operators Office - 2 units

5. Mud Room - 2 units

6. Spare - 4 units

Remote H2S sensors (usually installed and monitored by mudloggers) to bepositioned at the following locations:

1. Beneath rig floor, beside the flowline.

2. On the drill floor, near the rotary table.

3. Shale shaker house (at the return mud flowline and for house ingeneral).

4. Mud room (at the return mud flowline).

5. At air intake to accommodation.


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Audible and visual H2S alarms(Ref. Station Bill).

Portable H2S detectors are to be issued to personnel routinely working in

high risk areas. These should have earphones in high noise areas toensure that the alarm can be heard. Following personnel should beprovided with this equipment as a minimum:

1. Driller

2. Assistant Driller.

3. Derrickman.

4. Shaker Hand.

5. Mud Engineer.

6. Toolpusher.

7. Operators Drilling Supervisor.

When installing cascade systems, the following points should be considered:

Anticipated number of personnel needed in the working areas.

Working areas which will need to be accessed by personnel whilst hooked

up to the cascade system are:

1. Drill floor (doghouse, manifolds etc.).

2. Monkeyboard area.

3. Mud room (at pits, mixing areas and pumps).

4. Shaker house.

5. BOP and diverter control units.

6. Control and radio rooms.

5.6.2 H2S Drilling Practices

Drilling Fluids

The drilling fluid serves as the primary barrier to the effects of H 2S.Maintaining sufficient hydrostatic overbalance will minimise or eliminateingress of H2S gas.

Oil base muds offer the most protection to tubulars and metallicsurfaces by coating them with a thin oil film. These muds do not haveadverse theological reactions to H2S scavengers.


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Water base muds require considerable treatment for H2S inhibition andscavenging and unfortunately these treatments have an adverse effecton mud properties.

Maintaining the pH above 11.0 with caustic or lime will neutralise thecorrosive action of H2S. It is important to neutralise with a suitablescavenger following initial H2S detection.

Action To Be Taken If H2S Is Detected

If measurable amounts of H2S are detected while drilling, then the followingprocedures should be adopted:

1. Driller to pick up off bottom, shut down pumps and secure brake.

2. All personnel in direct of indirect contact with the mud system shouldstop working and put on breathing apparatus (30 - 60 min durationsets or escape sets hooked up to cascade system).

3. Shut well in at BOP stack by closing upper annular preventer.

4. Space out and land off tool joint on designated pipe rams. Lock rams.

5. Open annular and circulate riser through mud/gas separator until freeof H2S gas. Treat mud with H2S scavengers as required.

6. Circulate and condition mud, taking returns through choke to mud/gasseparator until free of H2S. Treat mud with H2S scavengers asrequired. If presence of H2S gas was due to insufficient mudweight, then raise mud weight as required.

5.6.3 General Precautions

Conduct H2S drills at frequent intervals to ensure correct crew response.

All non-essential personnel are to stay clear of all hazardous areas whencarrying out operations where the presence of H2S is possible.

It is important that H2S is vented to atmosphere in a safe area or burned off

through a flare line. It must not be vented in a confined area.

When recovering a core from a zone possibly containing H2S, all rig floorpersonnel are to use working breathing apparatus to pull and rack the BHA(when top of core barrel being approximately 1000ft below rotary table).

Regular testing for H2S should be carried out on the drill string before this. Onlywhen the core is at surface and has been checked and cleared for H2S, shouldbreathing apparatus be removed.

During drill stem testing of H2S zones, there can be considerable concentrationsof H2S in the produced flow stream. Personnel involved in the operation must

wear breathing apparatus at all times and personnel moving from one area toanother (e.g. rig floor to test separator area) must be accompanied (work in


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pairs). Only essential personnel should be in the hazardous areas and MUSTbe wearing suitable breathing apparatus.

When pulling tubing from an H2S well, it is important to test the tubing (with

sniffer) for H2S. If H2S is present, then a suitable scavenger should be pouredinto the tubing. Testing and addition of scavengers should only be carried outby personnel wearing appropriate breathing apparatus.

5.7 Shallow Gas

In the context of this section, shallow gas is considered to be gas that isencountered in a well which cannot be closed in, i.e. well shut-in pressurescombined with the hydrostatic head of the fluid in the well bore will probablyresult in formation breakdown and subsequent cratering of the well. If BOPprotection and normal well killing procedures can be applied, then the gas is notconsidered to be shallow gas.

Shallow gas is largely a hazard to drilling operations when drilling top hole andsetting surface casings before BOPs are installed on the well.

The following sections will describe:

The Companys philosophy and approach to the problems posed by shallow

gas accumulations offshore.

Explain the need for adequate and thorough site investigation to identify

shallow gas accumulations.

Recommended procedures for drilling and casing top hole sections.

The Companys approach is to avoid areas containing shallow gas at alltimes where possible. This approach relies on adequate knowledge of theproposed drilling site being obtained prior to the well being planned. Thisknowledge will be obtained from two main sources:

Data from offset well drilled close to the proposed location.

Data obtained from site survey(s) carried out by specialist contractors on the

proposed location.

This information should be made available by the Operator during pre-contract or pre-spud meetings to enable potential hazards to be identifiedand evaluated.

The Company considers that riser-less top hole drilling in floating drillingoperations is the preferred safe method.

The Company recognises that surface diverter equipment is limited in itsability to withstand an erosive shallow gas kick for a prolonged period oftime. Surface diverters are seen as a means of buying time to evacuatethe drilling site.


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The surveys should also include a review of all documentation andexperience gained in the area, such as sub-sea inspection reports fromplatforms, and end of well reports of nearby wells.

MWD (monitor while drilling) tools can be used to supply gamma ray andresistivity measurement information for pore pressure analysis whilst drillingthe well.

The use of pilot holes (12 or smaller) is recommended in areas where thechances of penetrating a shallow gas accumulation is high and the drill sitecannot be relocated. This will reduce the exposure area of the hole to theaccumulation and may enhance the chances of a dynamic kill being carriedout.

5.7.1Company Philosophy

The Companys shallow gas philosophy can be summarised as follows:

Avoid shallow gas where possible. Move the drilling site and drill a deviated

well if the site survey indicates a possible shallow gas accumulation.

Optimise the preliminary site investigation in accordance with UKOOA

Guidelines as expressed in the Seabed Survey Sub CommitteeTechnical Report - December 1990.

Drill riserless with floating drilling installations until formations are strong

enough to allow BOPs to be installed and normal well control

techniques can to be established.

Surface diverters are seen as a means of buying time to evacuate the

drilling site i.e. winching a floating rig off location.

In cases where it is deemed necessary to drill using a riser (e.g. mud weight

and viscosity is required to maintain the borehole) then a smalldiameter pilot hole of 12 or less should be drilled to casing point andthen opened up to the required diameter. This will limit the potentialgas flow in the event that a shallow gas accumulation is penetrated.

5.7.2Shallow Gas Kick Prevention

A shallow gas kick may be the result of the following:

Drilling into a shallow over-pressured gas zone (Ref: Rig Specific Work

Methods, Section 6).

Loss of primary well control (Ref. Well Control Manual, WCO 200).

Drilling into producing well.

Over-pressured shallow gas kicks are difficult to avoid once over-pressured

gas zones have been penetrated. The best defence against over-pressured gas is to attempt to minimise the risk by adhering to the followingpractices:


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Select drilling locations on the basis of expert interpretations of shallow

geophysical and geological data.

Examine offset well information for the area in question which gives usefulpointers to shallow gas.

Use a floating drilling vessel and drill riserless.

To minimise the loss of primary well control, implement stringent top holedrilling practices and procedures (Ref. Section 5.7.4).

Penetrating an adjacent well, may be a possible source of a shallowblowout. Producing wells with a collision risk should be closed and pluggedin accordance with Company Policy, (Ref. Section 5.11 in DOP 202). A

diverter system should always be employed if a collision risk exists, or ifthere is a chance of penetrating formations which are charged up by leakingor poorly cemented casing strings from nearby wells.

5.7.3Primary Well Control

Primary well control as described in the Company Well Control Manual(Ref. WCO 200) is the only means to protect the well from blowing outbecause secondary well control techniques are not normally applicable intop hole drilling operations. However, due to the shallow depth andweakness of top hole formations, it is impossible to use the normaloverbalance of 200 - 400psi. It is therefore most important that strict

practices and procedures are followed at all times to maintain primary wellcontrol, (Ref. Section 5.7.4).

There are four principal causes which may result in or contribute to theloss of primary well control:

Swabbing

Failure to fill the hole properly

Losses and insufficient mud weight

These topics are examined in greater detail in the Company Well ControlManual (Ref. WCO 200).

5.7.4Recommended Drilling Practices

These are applicable to drilling with or without riser.

A pilot hole should be drilled in areas with possible shallow gas. This will

reduce gas production in the event of a shallow gas kick. Considerusing MWD to provide early warning of increasing pore pressure.

Restrict the penetration rate. Care should be taken to avoid anexcessive build-up of solids in the hole leading to formation breakdownand losses. Restricted drilling will also minimise the penetration into thegas bearing formation which in turn minimises the influx rate.


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Every effort should be made to minimise the possibility of swabbing.Pumping out of the hole at optimum circulating rates is recommendedfor all upward pipe movements (making connections and tripping). This

must be done for wells drilled riserless with returns taken at theseabed as there is not way of monitoring the well state during trippingoperations. It is important that the circulation rate is sufficiently highand the pulling speed sufficiently low to ensure that no swabbing takesplace, (this pump out tripping operation may be carried out inconjunction with displacing the hole to viscous mud). The use ofstabilisers will also increase the risk of swabbing, hence the minimumnumber of stabilisers should be used.

Flowchecks should be made before tripping, after an increase inpenetration rate or pit level change is noted. It is recommended to flowcheck each connection whilst drilling the pilot hole in potential shallow

gas areas. Measuring mud weight in and out and checking for seepagelosses are all important practices which should be applied continuously.(The ability to monitor various parameters will be dependant uponwhether or not riser is being used, without riser the ROV could be usedto monitor the hole, its sonar may identify a gas plume).

A float valve (NRV) must be installed in all bottom hole assemblies (BHAs)

which are used in top hole drilling to prevent uncontrollable flow up thedrill string.

Large bit nozzles or no nozzles should be used to allow lost circulation

material to be pumped through the bit in the event of losses.

Shallow kick-offs should be avoided in areas of possible shallow gas. Top

hole drilling operations in these areas should be simple and quick tosee potential hole problems.

Floating drilling installations which have to drill using a riser should run a fill

valve on the riser immediately above the wellhead connector as thiscan be opened in the event of a shallow gas kick to keep the gas wetand minimise the chance of ignition, prevent evacuation and possiblecollapse of the marine riser.

Detailed location specific procedures should be developed for installationsdrilling in possible shallow gas areas. These procedures should consider:

1. Monitoring for gas in water around the installation.

2. Releasing and dropping the drilling string.

3. Diverter procedures where applicable.

4. Personnel assigned and trained for moving the installation off location(floating installations).

5. Shutdown procedures for ignition sources.


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6. Evacuation procedures for non-essential personnel in the first stages ofdiverting a well.

7. Closing procedures for water-tight doors and hatches.

8. Training should be carried out for all installation personnel and backedup with drills.

9. Keep to a minimum, the number of personnel on board during thisphase.

5.7.5 Emergency Procedures

Each installation has Emergency Procedures detailed within the Rig EmergencyPreparedness Manual. These procedures should be followed in the event thatshallow gas is encountered.

6.0 REFERENCES

None.

7.0 ENCLOSURES

None.

Documents

DOP 204 - Rev 4