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1. COILED TUBING OPERATING POLICIES

1.1 Corporate Standards for Quality Management of Coiled TubingServices.

1.1.1 Scope

These standards cover the purchasing, maintenance,pressure testing and rig-up and operations of coiled tubingequipment for all BJ SERVICES coiled tubing services.

These standards are to be used in conjunction with themanufacturer’s specifications and instructions.

1.1.2 Purpose

To ensure that minimum acceptable standards of performance and safety

are achieved throughout the company’s coiled tubing operations.

1.2 Tubing

1.2.1 Purchasing

Tubing will only be purchased from Precision Tubing Inc. or QualityTubing Inc. or their respective subsidiaries/distributors. Purchases fromother manufacturers must be approved by Corporate Engineering on acase by case basis.

Only tubing designated as 70k/80k low alloy low carbon steel with a

nominal yield strength not exceeding 90,000 psi when newly milled may be used as coiled tubing. Tubing manufactured from other materials maynot be used without consultation with Corporate Engineering. This

prohibition applies to tubing made by all manufacturers.

CT Operations & ProceduresCATR0010 Issue A

8/14/2019 Section 1 Page 1


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1.2.2 Receiving

All tubing must be accompanied with traceability certificates from themanufacturer when received. No tubing will be put into service unless BJ

SERVICES is in possession of the following documentation:• Ladle analysis showing all chemical components of the steel• Manufacturer’s inspection certificate showing :• Mechanical properties (hardness, tensile and yield strengths)

• Pressure test data• Weld log including weld type and location• Tube grade and serial numbers• Hydrostatic test report• NDT test reports• Shipping condition (corrosion prevention measures)• Identifying marks of each section of steel strip, joining weldsand taper details• Radiographs of production welds

• For Stiff Wireline reels, certification of cables integrity (electrical andmechanical)

During the first installation of the tubing on to a working reel check and record:

• The wall thickness at each end of the string, to confirm themanufacturer’s data and taper orientation.

• The number, location, type and appearance of all welded transverse joints.

• The overall string length.• Continuity and insulation of cable.




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1 .2 .3 Ma intenance

Each purchased string of coiled tubing will be allocated a BJ SERVICEStraceability number and all records of its use will be referenced to thatnumber.

All tubing handling operations that result in plastic deformation of thetubing will be recorded in sufficient detail that appropriate fatigue

predictions can be made. In addition cable slack will be monitored andrecorded for Stiff Wireline reels.

The accumulation of fatigue data and other related service factors will berecorded in the coiled tubing management system known as CYCLE. Theevent data will be entered into CYCLE as soon as possible after thecompletion of a customer service program.

1.2 .4 Corrosion Contro l

During periods between workovers appropriate actions must be taken tominimize corrosion from the inner and outer surfaces of the tubing.

Prior to any operation where internal debris, such as rust scale andcement for instance, may impair the function of a downhole tool or chemical treatment, the tubing will be cleaned using the appropriate‘pigs’ and de-rusting chemicals.

Prior to any operation where external corrosion products or corrosioninhibitor residues may impair the function of the Injector TractionSystem or Stuffing box, such measures as are appropriate will be taken toclean the outer surface of the coiled tubing.

For long term storage or in humid, salty environments, the coiled tubingneeds to be protected inside and out from the elements.




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1.2.5 Shipping & Handling

Coiled tubing must be shipped on a drum which has been designedspecifically for the purpose with a minimum core diameter of 40 timesthe pipe OD. For 2” and larger tubing or pipe weighing greater than 20

MT, the drum must be of welded steel construction with provision for attachment to a 6” OD shaft

Footage counters will be fitted to spoolers so that correct fatiguemonitoring data and total string length can be recorded during tubingmaintenance operations.

1.2.6 Welding

All field welded joints will be made using BJ SERVICES procedures (seesection 9) which must be approved by a relevant local inspectionauthority. Welding technicians must be qualified to carry out the welding

procedures by the same authority.

Each Region will develop and maintain welding procedures suitable tothe sizes of coiled tubing and the available welding equipment in theregion.

All welds made by BJ SERVICES personnel or by third parties acting assubcontractors to BJ SERVICES, will be carried out according to thefollowing minimum standards:




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Conditions Manual welding permitted

Orbital welding required

Wall th ickness >0.125”

No Yes

Tubing OD > 1.5” No YesWall th ickness <0.125”

Yes Preferred

Tubing OD < 1.5” Yes Preferred Wellhead

pressure<3,000 psiYes Preferred

Wellhead pressure>3,000 psi

No Yes

Sour service Not allowed Not allowed Injection pressureinduced hoop stress>50% yield stress

No Yes

Sour service will be defined as any well producing sour gas (H 2S)regardless of concentration.

Note : REGION Management approval is required to deviate from theabove parameters.

All welds will be:

• made with the aid of a mechanical alignment jig which can positionthe ends of the tube such that the external wall profiles are not morethan 0.005” out of line at any point on the circumference.

• inspected using radiographic non-destructive methods by a third party

and the inspection reports kept for the life of the string.• subjected to a pressure test to 80% of the burst pressure for the

lightest wall tubing in the string or the limit of the plumbing in thesystem. In addition the weld will be subjected to a rolling pressuretest in which the pipe should be spooled onto the spooling reel then

back onto the work reel at the same test pressure mentioned above.• hardness tested at both the weld bead and heat affected area and

remain below Rockwell 22 C for the test sample (the test weld prior to completion of final weld).

Note: CYCLE will need to be updated to include location of welds




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and cycles added to the coil tubing string.

1.2 .7 Service Conditions

Coiled tubing shall always be operated within an envelope defined by thefollowing conditions:

• Combinations of axial, hoop, radial and torsional loads shall bereduced to an equivalent triaxial stress using the Huber-Henkyrelationship for minimum distortion strain energy. (This method isimplemented in CIRCA..)

• The equivalent stress shall not be permitted to exceed 80% of themanufacturer’s minimum published yield strength of any giventubing without management consent.• All stress calculations shall be based on the nominal wallthickness for that size of tubing.

• Collapse and axial tension load combinations shall be assessedassuming a minimum of 0.025” ovality for all sizes of tubing.API5C3 should not be used alone to calculate collapse limits because

it is based on drawn tubing which has less ovality than coiledtubing .Note: (CIRCA should be used for collapse risk assessments. It employs both API5C3 recommended practice and an additional eccentricity model: the lower collapse limit being selected.)

• Ovality is the flattening of the coiled tubing as it is bent. It is definedas the difference between the largest and the smallest outsidediameters on a cross-section . Plastic deformation becomes a

permanent feature even when the pipe is straight.

Ovality = D max - D min

D




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Ovality may cause a significant reduction in the coiled tubing collapse pressure rating compared with that for perfectly round pipe.Maximum ovality affects sealing and gripping equipment andcollapse resistance. The operating limit for ovality is 5%.• Surface rippling occurs on the minor axis of the coiled tubingas a result of bending. Rippling typically occurs late in the fatiguelife of the coiled tubing and the tubing should be regularly inspectedfor rippling and consideration be given to withdrawing it fromservice if rippling is detected

• Dilation of coiled tubing due to the combined effects of bending andinternal pressure will be limited to not more than:

Dilation is defined as the average of the largest and the smallest outsidediameter on a cross-section. Dilation in excess of the following limitswill cause the coiled tubing to bind within the stuffing box and causesurface damage to the coiled tubing.

Coiled Tubing OD Dilation Limit up to 1.75” 0.050”>2” 0.070”

• Hydrogen blistering and cracking can seriously reduce thecoiled tubing strength• When sour conditions exist:1. tubing of designated yield strength 70,000 psi and hardness not

greater than Rockwell C22 will be used whenever possible.2. work strings may not have butt welded joints.

• Hydrocarbons shall never be produced through coiled tubing beingused in a workover mode unless the producing coil tubing is encasedin a protective safety barrier

• Natural gas shall not be used for gas lifting via the coiled tubingunless the coil tubing is encased in a protective safety barrier

• Air shall not be used for gas lifting via the coiled tubing.




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Note: Drilling operations using air are permitted provided appropriate procedures are defined and REGION Management approval has beengiven.• Wellhead temperatures shall not exceed the temperature rating of

elastomeric seals in the pressure control equipment.• Well temperatures should not exceed 660 ° F (350 ° C)• Running speeds during tripping shall be determined by each REGION

to suit local job requirements and equipment design. In no eventshall running speeds exceed 240 ft/min. (70 m/min)

1.3 Equipment

Note : The following standards can only be modified with written local REGION Management consent.

1.3.1 BOP’s

1.3.1.1 Minimum Purchase Standards

• Approved vendor • Complies with or exceeds NACE MR 0175 and API standards for

well control equipment• Minimum 10,000 psi (70,000 kPa, 690 bar) working pressure with a

15,000 psi (100,000 kPa, 1032 bar) test pressure• Minimum 3 1/16” (77 mm) ID• All shall be H 2S compatible• All BOP hoses will be fire proofed the first 50 feet (15 m) from the

well• All rams to be able to close in 15 seconds or less at minimum

temperature• Minimum configuration will be blind, shear, slip and pipe or

combination of these• Have a kill port with a minimum 2 1/16” (52 mm) flange• Ability to monitor wellhead pressure below the pipe rams• Pressure equalizing valves across all pressure containing rams• Use of only flanged/metal-to-metal connections below the lowest

blind rams• Slip design shall minimize fatigue/deformation damage (interrupted

profile, diamond or other pattern)• Slip rams shall be capable of holding the pipe up to the minimum

yield point at the maximum rated working pressure in a hang-off mode. In a “snub” mode, the should hold a minimum of 50% of the




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minimum yield of the coiled tubing• Have shear/seal feature• Shear rams capable of shearing the heaviest wall and highest yield

OD pipe the BOP is designed to accommodate at its maximum ratedworking pressure. Hydraulic pressure utilized to make this cut will

be less than 3000 psi (21,000 kPa, 206 bar)• Shear rams shall be capable of two or more successive cuts of the

above pipe while still leaving a fishable profile plus flow paththrough the pipe

• Shear rams must be capable of cutting slick or braided line cleanly• All rams to have a manual locking device capable of holding

maximum working pressure ratings as well as hydraulic operating pressure. The rams can only be opened hydraulically after the lock has been disengaged

• Accumulator should be sized to operate all rams one-and-a-half cycles (close, open close) at the maximum rated BOP working

pressure• All BOP’s will have tell-tale weep holes. Reason: If a seal fails the

well fluids or gasses will leak at the BOP rather than travel throughthe system back to the hydraulic reservoir at the unit

1.3 .1 .2 Pressure Testing & Rig-up

• Wellbore returns shall not be taken through the primary BOP kill line but through a “flow T or Cross”

• Minimum configuration shall be stuffing box, blind, shear, slip and pipe or combination of the above

• Anytime coil tubing is run into a well a BOP must be included as partof the pressure control equipment

• An annular BOP shall be used when BHA’s of larger OD than the coilwill have to hang across the Christmas tree due to length

• Initial pressure tests to the maximum test pressure required will be

with water or other suitable, non-flammable, solids free fluid. If fluid pumping equipment is not available on location, pressure testing may be conducted using nitrogen as the test fluid with the appropriatesafety precautions

• Dedicated kill line with pressure rating similar to BOP• BOP flange rating equal or greater than Christmas tree• All connections to be flanged below the lowest blind ram• As pipe and blind rams only hold pressure from below, the Christmas

tree swab valve needs to hold pressure in both directions to be able totest these rams

• All ring gaskets shall meet the requirements of API Spec. 16A,




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Section III C7. Coated ring gaskets are not to be used. Ring gasketsshould not be reused

• The elastomers used shall be appropriate for the service fluids usedand the anticipated temperature

• Flange studs and nuts to be of the correct size and grade and made-upto the proper torque in a criss-cross manner (See API Spec 6A)

• All well control equipment shall be tested using water or other suitable solid/gas free liquids (to protect against freeze-up)

• All well control components shall be subjected to first a low pressuretest generally 200-300 psi (1,400-2,100 kPa, 14-20 bar) for 5minutes (do not pressure up and bleed down as seals might energizeat higher pressures) then at a minimum the maximum anticipatedwellhead (not pumping) pressure plus 20%. Hold this and record for 10 minutes

• Test area shall be cordoned off and only necessary personnel shouldstay in test area

• Tightening, repair or any other work is to be done only after all pressure has been bled down.

1.3 .1 .3 Pre-Job Pressure Tests :

This tests and records all well components including CT, BHA, reelrotating joint, pump lines, kill lines and choke/flow lines and should becarried out and recorded at the maximum rated working pressure of theChristmas tree:

• Maximum working pressure is substantially below these pressures, usemaximum anticipated working pressure x 1.5

• Upon installation of components on wellhead• At least once every seven (7) days when installed (i.e. when stuck)

and/or prior to when normal operations resume• Prior to well testing operations

Note : If the maximum expected working pressure is substantially below therated working pressure, then test to the maximum anticipated working

pressure X 1.5

1.3.1.4 Maintenance

Post-Job as a minimum :

• Remove ram bonnets and visually inspect, clean and repair asrequired before each rig-up




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Pre-Job as a minimum :

• Hydraulically and mechanically activate all rams• Confirm correct insets are installed

After every 250 hours or 6 months, which ever comes first:

• Totally strip, inspect, clean and replace as required all components• Pressure test to maximum rated working pressure. This usually is done

in the yard against a test stump• Full body pressure test to its maximum rated working pressure• Testing of blind rams to their maximum rated working pressure• Testing of pipe rams to their maximum rated working pressure• Testing of slips to 80% minimum yield of hang-off and 50%

minimum yield of snub using maximum wall, OD and rated pressure(derived from manufacturer’s tables, load capacities.)

• Testing of cutting capability at max. working pressure, wall, OD andyield

• Note: Utilize old blades if possible for this test• Testing of equalizing valves• Drift bore of BOP body to ensure it is within specifications for BOP




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1 .3 .2 Stuffing Bo x

1.3.2.1 Minimum Purchase Standards• Approved vendor • Complies with or exceeds NACE MR 0175 and API standards for well

control equipment• Minimum 10,000 psi (70,000 kPa, 690 bar) working pressure with a

15,000 psi (100,000 kPa, 1032 bar) test pressure• H2S compatible• Have an injection port below the pack-off

• Have a “chemical injection port” above the packer elementsto allow 360

º

coverage of the pipe with a wide variety of anticorrosion chemicals or lubricating oils

Preference is given to :• Systems where the distance from the top of the upper

bushings to the chains is minimized• “Side removable” packer element designs (i.e. side-door,radial, etc.)• Dual acting hydraulic pack-off, ones that hydraulically

energize and release• The hydraulic energizing system should have “weep holes”to signify worn orings/seals• Benoil is the only approved stuffing box packer/energizer vendor for wellhead operation with pressures exceeding 3000 psi(21000 kPa) and or temperatures exceeding 212 0 F (100 0 C)

1.3 .2 .2 Pressure Testing & Rig-Up

• Any time coiled tubing is run, a stuffing box needs to be part of thewell control package.

• The elastomers and orings/seals used shall be appropriate for theservice fluids used and the anticipated temperature.

• All well control components shall be subjected to first a low pressuretest generally 200-300 psi (1,400-2,100 kPa, 14-20 bar) for 5 minutes(do not pressure up and bleed down as seals might energize at higher

pressures) then at a minimum the maximum anticipated wellhead(not pumping) pressure plus 20%. Hold this and record for 10minutes.

• If a N 2 test is required, a successful fluid test of all components to themaximum N 2 test pressure required will be carried out first.

• Test area shall be cordoned off and only necessary personnel shouldstay in test area.

• Tightening, repair or any other work is to be done only after all




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pressure has been bled down.

1.3 .2 .3 Pre-Job Pressure Tests :

See section 1.3.1.3.

1.3.2.4 Maintenance

Post-Job as a minimum :

• Disassemble and visually inspect, clean and repair as required beforeeach rig-up.

Pre-Job as a minimum :

• Hydraulically and mechanically activate• Confirm correct brass and packer inserts for job• Check that bushings have not worn more than 0.05” (1.27 mm)

After every 250 hours or 6 months, which ever comes first:

• Totally strip, inspect (visual or NDT), clean and replace as requiredall components

• Function/integrity pressure test to maximum rated working pressure.This usually is done in the yard against a test stump.

• Full body pressure test to its maximum rated working pressure• Full up and down movement of the hydraulic ram




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1.3.3 Work Reels


• The drive system must have a higher top speed than the injector • The shaft torque should be 1.5 times the line pull required for the

biggest, heaviest coil to be utilized• The minimum core radius needs to be forty-eight (48) times the

maximum pipe OD to be run on the reel. As large as possible i.e.1.25” / 72”, 1.50” / 90”, etc. (31.8 mm / 182 cm, 38.1 mm / 228 cm)

• Dynamic and mechanical reel brakes are required• The levelwind needs to be able to handle 80 degrees of elevation• The internal piping needs to be integral and have a minimum 10,000

psi (70,000 kPa, 690 bar) working pressure rated with at least one plug valve and ball drop “Tee”.

• The rotating joint shall be rated at 10,000 psi (70,000 kPa, 690 bar)working pressure.

• The rotating joint to have a non obstructed ID equivalent or larger than the maximum coil ID except 2 7/8” (73 mm) and 3 1/2”(88.9mm)

• All reels shall be counter drilled for “Stiff Wireline” applications.• The plug launcher shall be part of the internal plumbing.• There shall be a hydraulic fail-safe clamp on the levelwind.• A mechanical depth counter shall be mounted on the levelwind.• A pipe lubrication system, non hand spray, will be located somewhere

on the unit (i.e. - the stuffing box or levelwind)• Reel capacity is not the same for different coiled tubing sizes.

Capacity for any given reel can be calculated as follows;

L = ((A-F)/D) X (B/D) X (2C+B)/3.82

L = Reel capacity (feet)

A = Reel flange height (inches)F = Reel free board (inches)D = Coiled Tubing diameter (inches)B = Width of reel between flanges (inches)C = Core diameter (inches)




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1.3.3.2 Maintenance

Pre-Job / Post-Job as a minimum :

• Check all retaining bolts and set screws on all components, bearingsand sprockets, lubricate as required.

• Check the alignment of all gears and sprockets on the work reel andlevel wind.

• Inspect the weep hole on the reel swivel for evidence of leaks andensure that it is not blocked or obstructed.

• Inspect the reel motor and braking system.• Inspect the depth measurement equipment.• Inspect and refill the tubing lubrication system as required.

After 250,000 running feet (75,000 m) or 3 months:

• Check all retaining bolts and set screws on all components, bearingsand sprockets, lubricate as required.

•

Remove all drive chains and check condition of chains, gears andsprockets.• Check the operation and settings of the system relief valves and pop-

off valves where fitted. (hydraulic and tubing lubrication systems)• Check the efficiency of the reel drive and braking systems.• Remove, disassemble and redress the reel swivel.• Remove and check the condition of all chains and sprockets on the

level wind.• Remove the level wind yoke cover and inspect the condition of the

yoke and leadscrew.• Check the condition of the level wind trolley.• Raise and lower the level wind, inspect the condition of the hydraulic

rams.• Check the condition of the depth measurement device, i.e. measuring

wheel, bearings, chain and reduction gears.




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1.3.4 Injectors


• A minimum of 50% snubbing capability verses pulling.• Snubbing force which is 120% of the maximum anticipated by the

Circa prediction both while the coiled tubing is stationary and while

it is moving at speeds up to 30 ft/min (10 meters/min)• A dynamic braking system that prevents the coiled tubing from

moving when no hydraulic pressure is being applied to the hydraulicmotors. Also a secondary mechanical brake which is setautomatically or manually when the injector is stopped. Brakingsystems must be capable of holding the maximum pulling force andthe maximum snubbing force.

• The chains should be able to achieve maximum pull without the aid of coatings.

• The ability to change pipe size without the need to remove the chain(i.e. - inserts).

• The maximum speed should be 240 ft/min. (70 m/min)• Some means of support to prevent loads being transmitted to the

wellhead.• Note: The base must be strong enough to support the load of tubing

suspended in the well as well as the injector.• The injector frame and pad eyes rated to the injector weight plus the

maximum rated pull.• An accumulator on the skate traction hydraulic system.• An adjustable mounting system for the gooseneck.• The load cell shall be dual acting.• The weight indicator will have “heavy/light” readings when rated

above 50,000 lbs (22,200 daN) or is electronic.• A chain tensioning system• A drip tray to catch and contain chain lubrication•

Pad eyes for lateral re-strainment• A ladder for access to the gooseneck • A non-slip cover on top of injector • The ability to pull test to 120% of the maximum anticipated by

CIRCA prediction, while stationary and while the coiled tubing ismoving at 30 feet/min (10 m/min)

• Must have a maintenance odometer installed.

1.3.4.2 Maintenance





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• Inspect and grease all bearings and bearing carriages asrequired.• Check all chain tension rams for leaks and ensure theyoperate fully.• Check the injector chain roller bearing or roller carriages andlubricate as required• Check the gripper blocks for damage or excessive wear andclean gripping surfaces. Do not steam clean.• Check chain tension accumulator pressures.• Check the weight indicator system and pump up if required.• Inspect the depth measurement devices if equipped.• Inspect and replace the gooseneck rollers as required andlubricate as required.

After 250,000 running feet (75,000 meters) or 3 months:

• Remove the injector chains from the injector head. Inspect all bearings, gripper blocks and chain components for wear or damage.Lubricate as required.

• Check for free play or slack in the chain. The limit is 3 % stretch.• With the chain removed, check the condition of the skate for

excessive wear or damage. Reverse or replace as necessary.• Check the rollers and roller carriages. Lubricate as required.• Check the nitrogen pre-charge on the chain tension circuit

accumulators. (Manufacturers recommended pressures should beadhered to at all times.)

• Perform pull test.• Inspect the weight indicator system.• Inspect the depth measurement devices if equipped.• Check the gooseneck and rollers for excessive wear or damage.




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1.3 .5 Pipe Stra ighteners

• Will be supplied when running pipe greater than 2”(50.8 mm) in OD.• Only to be used when required (i.e. - completions ; before and after

connections).

1.3.6 Gooseneck (Tubing Guide Arch)


• Needs to be adjustable. The pipe should enter and exit the guide archtangent to the curve of the guide arch

• The guide arch radius needs to be at least 48 times the coiled tubingOD.

Note: A radius larger than 100 inches (254 cm) does not gain significantadvantages.

• The closer the rollers are spaced, the better.• The gooseneck needs to be strong enough to handle the combined

bending of the pipe, withstand the bending moment that maximumreel back tension would apply and a 5% side moment (fleet angle)that happens when you are spooling at the extreme sides of the reel.

• The end of the gooseneck should be flared. This flare shouldaccommodate the maximum fleet angle that it will see without the

pipe seeing another strain reversal.

1.3.7 Power Packs & Control Cabin


• The engine size needs to be able to handle the injector plus theauxiliary systems at maximum load with a 50% safety factor.

• The hydraulic system to be able to dissipate maximum heat output.•

The control cab window shall be protected or have bullet proof glass.• The blind and shear ram controls on the control panel shall have positive locks.

• The accumulator charge shall be sized to handle Open, Close, Openscenario of all rams at the maximum BOP rated working pressure.

• The hydraulic system for the BOP’s and stuffing box shall have two back-ups (i.e. air and manual).

• Depth, speed, wellhead and pumping pressure and weight need to bedisplayed along with the power pack hydraulic/air parameters (i.e. -traction force, skate tension, well control, reel back tension, injector hydraulic pressure, stuffing box hydraulic......).




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1.3.7.2 Maintenance


• Check all fluid levels.• Check, clean or replace the air filter.• Ensure all gauges and controls are operational.• Check the fan and alternator belts for tension and deterioration.• Check and lubricate all engine control and instrument cables, angle

drives, linkages and pneumatic actuators.• Inspect the radiator for dirt and damage. Inspect hose connections and

clamps for leaks.• Check the operation of the starter and throttle. Observe oil pressure

and temperature. Tune the engine as required.

1.4 Equipment Rig Up

• Dual check valves shall be run at all times.• All shoulders of the BHA (reduce to minimum) shall have minimum

45°

taper.• A release tool shall be run when running any BHA that has a potentialof becoming stuck in the well and with all BHA’s in excess of 15’(4.5 m).

• If possible, spot the equipment upwind from the wellhead.• Install legs or support the injector.• Tie down the injector to minimize the bending moment on the

wellhead/connections.• Count the number of turns to open/close the master valve and record.• Cordon off and mark all areas that will contain pressure or where

dangerous fluids are being mixed/transferred.• Place safety equipment if operating in an H 2S area.• Use proper flow iron (not treating iron) downstream the flow “Tee or

Cross”.• Hold pre-job meeting before commencing the job.• Have MSDS sheet at hand for each fluid being pumped.

Crane Operation :

• Personnel shall be fully trained and certified in its use.• Crane shall be inspected at a government required frequency by a

recognized authority.




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1.5 Pre- Job Engineering

To ensure a consistently high standard of success in field operations, all jobs will be designed according to the following schedule:

1.5.1 Problem Statement

The customer will be requested to provide a clear statement of the problem to be solved and of the key factors required for success.

1.5.2 Well Description

Before preparing a workover proposal the BJ SERVICES representativewill obtain from the client a current completion diagram, well productiondetails and a directional profile along with any details of any damage or abnormal conditions in the completion, e.g. holes, buckled completion,etc.

1.5.3 Engineering A nalysis

The specifics of the work program will be analyzed usingCIRCA/CYCLE etc. to determine:• Flowrates and injection pressures of the treatment fluids.• Wellbore hydraulics, returns handling requirements, pressure control

requirements.• Tubing forces, weight indicator predictions, snubbing/pulling limits

for the intended coiled tubing size.• Triaxial stress analysis for the principal loading patterns during the

job.• Buckling and lockup potential in highly deviated wells and/or wells in

which tubing weight will be set down.• Fatigue accumulation.

1.5.4 CIRCA Analysis

CIRCA must be used whenever the proposed program of work on a wellmay involve:

• Wells over 30 0 deviation.• Wellhead pressures over 1,000 psi (7,000 kPa, 69 bar)• Any bottom hole tool manipulation (e.g. DUCT, Stiff Wireline,

Fishing, etc.).• Debris clean-outs (including Roto-Jet, Sand-Vac, etc.).




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Note: N2 clean outs are presently excluded since CIRCA cannot model them atthis time.• Cement jobs.• Reverse flow.• Running deeper than 12,000 feet (3,650 m) or using tapered strings.• An operation that requires over pull or set down weight to operate.• An operation where collapse might be an issue.• High rate oil or gas wells.

1.5.5 CYCLE Analysis

A fatigue analysis will be carried out whenever the proposed program of work on a well may require:

• More than one trip into the hole is anticipated.• The nature of the work will result in multiple cyclic movements over

a specific section of the coiled tubing.• The tubing is 1 3/4” (44.5 mm) OD or larger.• Pumping pressures above 3,500 psi (24,000 kPa, 241 bar) .




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An assessment of the fatigue damage will then be made using theCYCLE system. This assessment will be used to select the most suitablecoiled tubing string for the proposed program.

Workover programs must be designed to minimize fatigue damage to thecoiled tubing whilst achieving the desired service to the customer. The

probable cost of the fatigue damage should be included in job costing

whenever possible.

1.5.6 Fishing/BHA Diagrams

Coiled tubing shall not be run into a well unless a dimensioned drawingof the bottom hole assembly is available on location.

1.5.7 Contingency P lanning

When operations are planned in conjunction with third party contractors,or, at the request of the customer, an analysis of the potential modes of failure will be made prior to the commencement of the work.

Each REGION will maintain a set of localized contingency proceduresfor potential failure modes of associated region specific equipment ( e.g.lifting frames) and environments (e.g. desert, arctic, H2S, etc.). All localequipment operators, supervisors and operations engineers will receiveregular training and familiarization with these procedures.




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1.5.8 Job Program

Customized procedures shall be prepared by suitably experiencedoperations engineers or coiled tubing supervisors for all wells in whichone or more of the following conditions exist:

• Wellhead pressures > 1000 psi.(7,000 kPa, 69 bar)• H2S potential.• Wellhead temperatures > 212 o F (100 o C).• Deviation angles >30 o.• Solids will be produced/circulated from the well.• Cement is to be placed via the coiled tubing.• Milling, drilling or under-reaming to be carried out.• Reverse circulation via the coiled tubing.• Stiff Wireline.• Any job not regularly performed by BJ SERVICES in that locality.• Tools operated by forces derived from the coil tubing string.• Special rig up arrangements, i.e. floaters, etc.

Written workover procedures, CYCLE and or CIRCA where applicable,must be available on location prior to the commencement of operationswhen one or more of the above conditions apply.

1.6 Job Execution

To ensure a consistently high standard of success in field operations, all jobs will be performed according to the following schedule:

1.6.1 Job Preparation• Equipment shall be designated based on job requirements.• Equipment shall have been operationally checked off.• Personnel shall be selected based on job requirements and their

competencies.• Operational personnel shall be briefed on job objectives.




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1.6.2 Execution

• Pre-job meetings shall be held covering as a minimum safety,chemicals, contingencies, reporting lines, etc.

• Job to be executed as per program. Any variances shall be pre-approved by the company man unless safety is going to becompromised.

• As a minimum, all jobs will have the wellhead and annulus pressuresas well as the injector forces recorded verses time.

1.6.3 Post Job Debriefing

• Review of equipment, personnel and service and plan with deadlinesto resolve any deficiencies.

• Review of treatment results verses objectives and plan with deadlinesto resolve any deficiencies.

• Filing of job data• Updating CYCLE and job database




Section 1

CT Operations & Procedures

CATR0010 Issue A

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