Drilling Manual

Drilling Manual GENERAL CONTENTS CHAPTER

SUBJECT

1.

B.O.P.EQUIPMENT

2.

WELL CONTROL

3.

ENVIRONMENTAL CONSIDERATIONS

4.

DRILLSTRING

5.

OPERATIONS

6.

DRILLING FLUIDS

7.

DRILLING EVALUATIONS

8.

FISHING

9.

DIRECTIONAL DRILLING

10.

DRILLING SPECIALITY TOOLS

11.

CEMENTING

12.

SURVEYING

13.

COMPLETION FLUIDS

14.

PERFORATING

15.

STIMULATION

16.

WELL EVALUATION AND PRODUCTION TESTING

17.

REMEDIAL CEMENTING

18.

SUSPENSION AND ABANDONMENT

Contents

1. B.O.P. EQUIPMENT .............................................................................................................I 1.1 Introduction ...................................................................................................................I 1.2 Diverter Systems...........................................................................................................I 1.2.1 Diverter on marine conductor pipe .......................................................................I 1.2.2 Diverter outlets and valves ...................................................................................I 1.2.3 Diverter operating unit and operating panel .........................................................I 1.3 Large bore (21¼”) BOP stack (flanged connections)...................................................II 1.3.1 Configuration.......................................................................................................II 1.3.2 Outlets.................................................................................................................II 1.4 Small bore (13 5/8”) BOP stack (flanged connections) .................................................II 1.4.1 Configuration.......................................................................................................II 1.4.2 Outlets............................................................................................................... IV 1.5 BOP Stack Control System ......................................................................................... V 1.5.1 Configuration...................................................................................................... V 1.5.2 Control panels .................................................................................................... V 1.6 Choke manifold (flanged connections)........................................................................ V 1.6.1 Configuration...................................................................................................... V 1.6.2 Layout ................................................................................................................ V 1.6.3 Kill and choke lines ........................................................................................... VI 1.7 Mud/Gas Separator................................................................................................... VII 1.8 Degasser................................................................................................................... VII 1.9 Trip Tank ................................................................................................................... VII 1.10 Stripping tank .......................................................................................................... VII 1.11 Additional Equipment for Stripping with an Annular Preventer .............................. VIII 1.12 Additional Well Control Equipment........................................................................... IX 1.12.1 Mud pit level indicator ..................................................................................... IX 1.12.2 Drill string shut-off equipment ......................................................................... IX 1.12.3 Pressure and function testing.......................................................................... IX 1.12.4 Winter operations ............................................................................................. X

Illustrations

Figure 1.1 Large bore 211/4” BOP stack..................................................................................III Figure 1.2 Small bore 135/8” BOP stack ................................................................................. IV Figure 1.3 Choke manifold layout .......................................................................................... VI Figure 1.4 Kill and choke manifold........................................................................................ VII Figure 1.5 Stripping set-up................................................................................................... VIII Figure 1.6 Surge bottle set-up ............................................................................................. VIII

Forms

Form 1.1 Well control equipment check................................................................................. XI Form 1.2 Weekly well control inspection................................................................................ XI

1. B.O.P. EQUIPMENT

1.1 Introduction The following BOP equipment is required: •

A rig integrated diverter system.

•

A two-stack system containing a large bore and a small bore BOP stack.

NOTES: All BOP equipment must be H2S resistant.

1.2 Diverter Systems 1.2.1 Diverter on marine conductor pipe •

After installation (pre-drilled or driven) of the marine conductor and prior to starting to drill the hole for the surface casing string, the diverter has to be installed.

•

The diverter should be a rig integrated unit installed under the rotary table. (Regan KFD or similar). The unit is permanently installed. The minimum rated working pressure is to be 34.5bar (500psi).

•

The unit is hydraulically operated using remote control panels.

1.2.2 Diverter outlets and valves The diverter must be equipped with three outlets. Each outlet must include a remote operated valve (hydraulic). These valves must be of a full opening type. The minimum required ID of each diverter outlet line shall be 12”. •

One line towards the port side of the rig.

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One line towards the starboard side of the rig.

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One line to the flowline.

The diverter system should incorporate a kill line complete with a check valve. 1.2.3 Diverter operating unit and operating panel •

The diverter unit should be operated with a self-contained accumulator and control system. This unit should be located in a safe area away from the rig floor.

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The diverter control system operator should be capable of operating the diverter unit from two locations, one of which has to be near the driller’s position.

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The control panels should have the minimum of functions. The control systems should be hooked up in a way that whilst closing the packing element always one valve in either the starboard or port side ventline stays open. A proper selection can be made later depending on the wind direction. Whilst closing the diverter packing element the flow line valve must be closed.

•

Installation requirements for wellhead and BOP equipment also apply to diverter equipment.

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The diver housing complete with spacer nipples will also be used as “bell nipple” on top of BOP stacks to be placed at a later stage. Therefore, sufficient spacer nipples and crossover joints must be available.

1.3 Large bore (21¼”) BOP stack (flanged connections) 1.3.1 Configuration After setting and cementing the surface casing string and the installation of a casing head housing, a large bore BOP stack must be installed. The configuration of this BOP stack (from top to bottom) is as follows: •

One 21¼” annular preventer working pressure 138bar (2 000psi).

•

One RAM type preventer equipped with proper sized Pipe RAMS, working pressure 138bar (2 000psi).

•

One RAM type preventer equipped with Blind or Shear RAMS, working pressure 138bar (2 000psi).

The large bore configuration is shown in Figure 1.1.

1.3.2 Outlets The lower RAM type preventer also has two 3” flanged side outlets; one kill line and one choke line. The kill line must be provided with two manually operated 3”-138bar (2 000psi) gate valves, and a 3” check valve. The choke line must be equipped with one manually operated 3”-138bar (2 000psi) gate valve and one 3”- 138bar (2 000psi) hydraulically operated valve (HCR).

WARNING: In the drilling phase, the side outlets on the casinghead housing must be equipped with two side outlet valves each.

1.4 Small bore (13 5/8”) BOP stack (flanged connections) 1.4.1 Configuration After the setting and cementing of the intermediate casing and the installation of a casing spool, the small bore 135/8” BOP stack must be installed. The configuration (top to bottom) is as follows: •

One 135/8” - 345bar (5 000psi) annular preventer.

•

One 135/8” - 690bar (10 000psi) RAM type preventer equipped with pipe RAMS.

Figure 1.1

Large bore 211/4” BOP stack

•

One 135/8” - 690bar (10 000psi) RAM type preventer equipped with blind/shear RAMS.

•


The small bore configuration is shown in Figure 1.2.

Figure 1.2 Small bore 135/8” BOP stack 1.4.2 Outlets The middle RAM type preventer must have TWO 3”-690bar (10 000psi) flanged side outlets for the kill and choke lines. The kill line must be provided with two 3”-690bar (10 000psi) manually operated gate valves and a 3”-690bar (10 000psi) check valve. The coke line must have one 3”- 690bar (10 000psi) manually operated gate valve and one 3”-690bar (10 000psi) hydraulically operated gate valve (HCR).

WARNING: During the drilling phase the side outlets of the latest installed casing spool must each have a double set of gate valves.

1.5 BOP Stack Control System 1.5.1 Configuration BOP stack control systems consist of a independent automatic accumulator unit rated for 207bar (3 000psi ) working pressure with a control manifold. The control manifold should clearly show the “open” and “closed” positions for the preventers and the hydraulically operated valves. The accumulator unit must be equipped with 0-207bar (0-3 000psi) regulator valves (TR5 type) which must be “fail safe” (to prevent loss of operating pressure). The capacity of the accumulator must be sufficient to execute the following without recharging: •

Closing and opening all preventers.

•

Closing the annular preventer again.

•

Closing one RAM type preventer.

•

Keeping all the above mentioned closed against the rated working pressure of the preventers.

The unit should be located in a safe area away from the rig floor. It should include a low pressure warning alarm and a hydraulic fluid level indicator or a low fluid level warming alarm.

1.5.2 Control panels The BOP stack should have two graphic remote control panels: each of the panels should indicate the “open” and “close” positions for each preventer, the hydraulically operated valves, and the bypass valve on the unit. One panel should be located near the driller’s position and the other panel should be located near the rig supervisor’s office.

WARNING: Fire resistant high pressure control hoses (steel wrapped co-flex type) with a working pressure of 207bar (3 000psi) must be used for the hydraulic control lines.

1.6 Choke manifold (flanged connections) 1.6.1 Configuration The coke manifold must have a working pressure of 690bar (10 000psi) and must have at least two adjustable chokes, of which one must be remotely operable from near the driller’s position. The minimum size for all choke lines and valves is 3”.

1.6.2 Layout An acceptable choke manifold layout is given in Figure 1.3.

Figure 1.3 Choke manifold layout 1.6.3 Kill and choke lines The kill and choke lines should preferably be a set of 3”-690bar (10 000psi) Coflex-hoses, provided with 3”-690bar (10 000psi) flange connections. The hoses should be of sufficient length to prevent sharp bending and all connections must have safety slings. The kill and choke lines will tie into a kill and choke manifold, giving multiple choice functions as given in Figure 1.4.

Figure 1.4 Kill and choke manifold

1.7 Mud/Gas Separator Free gas in contaminated mud that is leaving the choke manifold will be separated in the mud/gas separator. This separator can be designed as a horizontal or a vertical unit. The vent line of the separator should be large enough to minimise backpressure (8” or larger), and the separator capacity should be sufficient to handle the fluid/gas flow bleed off from the choke manifold. The (contaminated) mudflow leaving the separator shall have further treatment in the degasser.

1.8 Degasser The degasser separates the remaining gas from the contaminated mudflow coming from the separator. The degasser functions by creating a vacuum above the mud in the degasser, thus enabling gas evacuation from the mud. The degasser must have a proper vent system.

1.9 Trip Tank The trip tank must be totally isolated from the main mud system (i.e. no common manifolds). A minimum useable volume of 3m2 is required. This size requirement results in a field level change of 1” equating to a volume change of 0.075m3.

1.10 Stripping tank If a well starts kicking whilst tripping, primary well control has to be re-established. The safest way to do this is to close the well and strip the pipe string through the preventers back to the bottom, and kill the well by circulating to proper mud. For this operation a calibrated stripping tank is necessary.

A schematic stripping set-up is given in Figure 1.5.

Figure 1.5 Stripping set-up

1.11 Additional Equipment for Stripping with an Annular Preventer The surge pressures that arise in the hydraulic operating system whilst stripping through an annular preventer need to be dealt with. This is done by incorporating a surge bottle in the system (see Figure 1.6). This surge bottle has to be positioned as close as possible to the preventer.

Surge bottle 10 gal. c/w Nitrogen cushion (koomey bottle) WP=207bar (3000psi) Precharge=27bar (400psi)

ANNULAR BOP opening line

open

close

Closing line from accumulator unit c/w TR type regulator valve

P-gauge 200bar

Figure 1.6 Surge bottle set-up For stripping the drillstring has to be equipped with an R.H. Kelly cock and a “Gray” valve (check valve).

1.12 Additional Well Control Equipment 1.12.1 Mud pit level indicator To record all gains and losses of mud a sensitive pit level and recording system should be installed in the active mud tanks. This system should also give audible and visual alarm signals on preset high and low levels in the mud tanks.

1.12.2 Drill string shut-off equipment A kelly cock (LH) must be used on the kelly below the swivel at all times. In addition, a full opening lower kelly cock (RH) with a minimum internal diameter equal to or greater than that of the drill collars is to be run between the kelly and the kelly saver sub. A top drive must contain a hydraulically operated upper kelly cock. A drillpipe kelly cock in the open position with minimum bore equal to or greater than the internal diameter of the drill collars is to be readily available to the rig floor at all times. It is to be properly marked and must have collapsible, removable handles attached. It must be kept in the doghouse or other readily accessible place to prevent freezing or contamination. Crossover subs from the valve to the drill collars are to be kept with the valve at all times. Crossover should be a DC lift sub with DP thread up and fishing neck of DC OD. A “gray” style inside BOP with minimum internal diameter equal to the internal diameter of the DC’s is to be readily available to the rig floor at all times. It is to be sufficiently housed or shielded from freezing or contamination. It is to be properly identified and have collapsible, removable handles.

1.12.3 Pressure and function testing Prior to drilling out surface, intermediate or production casing and to a maximum of 14 days thereafter, the following pressure tests are to be conducted and reported in the tour book: d A B C

D

SIZE 29 1/2” HYDRIL 26” RAMS 21 1/4” HYDRIL 21 1/4” RAMS (DOUBLE) 13 5/8” HYDRIL 5 13 /8” RAMS (DOUBLE + 1 SINGLE) 13 5/8” HYDRIL 13 5/8” RAMS (DOUBLE + 1 SINGLE)

WP(BAR) 69 207 138 138 345 690

TEST PRESSURE (BAR) 35/20 50/20 100/25 135/25 345/25 345/25

690 1035

345/25 750/25

•

Surface equipment. All surface equipment shall be tested to its maximum rated working pressure but not lower than 345bar.

•

Casing. Casing should not be exposed to any (test) pressure higher than 80% of the burst pressure of the weakest joint of the casing.

•

The annular preventer will be mechanically tested by closing on drillpipe or collars once each day.

•

The pipe rams will be mechanically tested by closing on drillpipe once each day.

•

The blind ram will be mechanically tested by closing after each trip out of hole. Ram is to remain open while out of hole.

•

The hydraulic valve and remote controlled choke are to be mechanically tested by opening and closing once each day.

1.12.4 Winter operations The choke line and manifold will be kept free of ice plugs by filling with a glycol-based antifreeze solution and maintaining a 1.0 to 2.0bar pressure on the line by using an independent low volume pump. Notification of a closed manifold and revised kick control procedures must be posted in doghouse. Line from manifold to degasser inlet is to be filled with glycol solution.

Form 1.1 Well control equipment check

Form 1.2 Weekly well control inspection

Contents


Illustrations

Figure 1.1 Large bore 211/4” BOP stack..................................................................................III Figure 1.2 Small bore 135/8” BOP stack ................................................................................. IV Figure 1.3 Choke manifold layout .......................................................................................... VI Figure 1.4 Kill and choke manifold........................................................................................ VII Figure 1.5 Stripping set-up................................................................................................... VIII Figure 1.6 Surge bottle set-up ............................................................................................. VIII Forms


2. B.O.P. EQUIPMENT



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Figure 2.1


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open

close


P-gauge 200bar




2.12.3 Pressure and function testing Prior to drilling out surface, intermediate or production casing and to a maximum of 14 days thereafter, the following pressure tests are to be conducted and reported in the tour book:

A B C

D


WP(BAR) 69 207 138 138 345 690


690 1035

345/25 750/25

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Contents


Illustrations

Figure 1.1 Large bore 211/4” BOP stack..................................................................................III Figure 1.2 Small bore 135/8” BOP stack ................................................................................. IV Figure 1.3 Choke manifold layout .......................................................................................... VI Figure 1.4 Kill and choke manifold........................................................................................ VII Figure 1.5 Stripping set-up................................................................................................... VIII Figure 1.6 Surge bottle set-up ............................................................................................. VIII

Forms


3. B.O.P. EQUIPMENT



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Figure 3.1


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open

close


P-gauge 200bar




3.12.3 Pressure and function testing Prior to drilling out surface, intermediate or production casing and to a maximum of 14 days thereafter, the following pressure tests are to be conducted and reported in the tour book:

A B C

D


WP(BAR) 69 207 138 138 345 690


690 1035

345/25 750/25

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Contents

2. WELL CONTROL ..............................................................................................................4.I 2.1 Introduction ................................................................................................................4.I 2.1.1 Specific causes of kicks ....................................................................................4.I 2.1.2 Indications ........................................................................................................4.II 2.1.3 When to flow check ..........................................................................................4.II 2.1.4 Flow check procedures ...................................................................................4.III 2.2 Well Control General Shut In Policy........................................................................ 4.IV 2.3 Special Shut In Procedures..................................................................................... 4.IV 2.3.1 Offshore bottom supported units..................................................................... 4.V 2.3.2 Floating unit (drillstring compensator operational). ....................................... 4.VII 2.3.3 Floating unit (drillstring compensator non-operational). ................................. 4.IX 2.4 Drilling Well Control Methods.................................................................................. 4.XI 2.4.1 Concurrent method. ...................................................................................... 4.XII 2.4.2 Low choke method .......................................................................................4.XXI 2.4.3 Top kill method............................................................................................4.XXII 2.4.4 Driller’s method ..........................................................................................4.XXIII 2.4.5 Wait and weight method.............................................................................4.XXIII 2.4.6 Bullhead method ....................................................................................... 4.XXIV 2.5 Completion Well Control Methods....................................................................... 4.XXV 2.6 Tripping : Equipment, Procedures and Record Keeping.................................... 4.XXIX 2.7 Leak-Off Tests................................................................................................... 4.XXXII 2.8 Crew Training................................................................................................... 4.XXXIX 2.9 General Requirements ..................................................................................... 4.XXXIX 2.9.1 Surface casing wear prevention.............................................................. 4.XXXIX 2.9.2 Casing wear, tool joint wear and drillpipe protectors..................................... 4.XL 2.9.3 DST interval .................................................................................................. 4.XL 2.9.4 Production casing slip and seal assemblies.................................................. 4.XL 2.9.5 Drillpipe floats................................................................................................ 4.XL 2.9.6 Casing changeovers ..................................................................................... 4.XL 2.9.7 Stabbing valves and IBOP’s......................................................................... 4.XLI 2.9.8 BOP changeovers while running casing ...................................................... 4.XLI 2.9.9 Waste oil disposal ........................................................................................ 4.XLI

Illustrations

Figure 2.1 Well control worksheets (steps 1 through 4).....................................................4.XV Figure 2.2 Well control worksheets (steps 4 through 8)....................................................4.XVI Figure 2.3 Modified concurrent method ..........................................................................4.XVIII Figure 2.4 Hole fill equipment set-up ............................................................................. 4.XXIX Figure 2.5 Graphical trip sheets..................................................................................... 4.XXXI Figure 2.6 Completed leak-off test (no leak-off)........................................................... 4.XXXIV Figure 2.7 Completed leak-off test (normal) ................................................................. 4.XXXV Figure 2.8 Incomplete leak-off test (filtration losses) ................................................... 4.XXXVI Figure 2.9 Leak-off test (open hole)............................................................................ 4.XXXVII Figure 2.10 Completed leak-off test (casing shoe cement failure)............................. 4.XXXVIII Figure 2.11 Extended leak-off test (formation fractured) ........................................... 4.XXXVIII Tables

Table 2.1 Advantages and disadvantages of well kill methods....................................... 4.XXV Forms

Form 2.1 Graphical well control worksheet (page 1 of 4) ................................................ 4.XLII Form 2.2 Well control worksheet ..................................................................................... 4.XLII Form 2.3 Well control log ................................................................................................ 4.XLIII Form 2.4 Graphical trip sheet .........................................................................................4.XLIV Form 2.5 Leak-off test......................................................................................................4.XLV Form 2.6 Blowout prevention drill ...................................................................................4.XLVI Form 2.7 Trip record (A3 page)

4. WELL CONTROL

4.1 Introduction An imbalance of the formation pressure being higher than the hydrostatic pressure will allow invading formation fluids to enter the wellbore. It is very important that the drilling personnel understand the causes of kicks in order to prevent them from becoming uncontrollable. Regular meetings should be held with the crews to discuss potential drilling situations which could lead to a kick. The first line of kick detection is a well-trained crew. 4.1.1 Specific causes of kicks The vast majority of kicks are caused by human error. It is extremely important that the drilling crews be aware of the primary causes of kicks. In addition, the Company Representative must be aware of well conditions that could lead to a kick (i.e., drilling within a water flood). These conditions must be passed onto the crews. Primary causes of kicks are as follows: •

Not keeping the hole full. Statistics show that 60 to 80% of all blowouts occur while pulling pipe and not filling the hole with the correct volumes. When theoretical accumulated volumes are compared with actual accumulated volumes, an accurate indication of whether the hole is taking the correct fill-up volume is easily determined. For this reason trip sheets must be kept. Companies prefer the use of a graphical trip sheet. In addition, all rigs are to utilise continuous hole fill pumps while tripping.

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Swabbing the hole. Swabbing may cause a reduction in hydrostatic pressure, allowing an influx of formation fluids. The greatest danger of swabbing occurring is when the pipe is close to the bottom. The factors affecting swabbing are the: − Hoisting speed. − Annular hole clearance. − Mud properties. − Balled-up bit. − Nozzle sizes.

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Insufficient mud density. In addition to insufficient mud density allowing a kick to occur, too high a mud density can also cause well control problems: − May exceed fracture gradients causing lost circulation. − High densities can cause differential sticking. − High densities can impair formation productivity.

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Lost circulation. If lost circulation occurs while a kick is being handled with pressure on the preventers, an underground blowout may occur. The zone of lost circulation must be repaired before normal well control procedures may be implemented.

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Abnormally pressured zones. Charged or abnormally pressured formations are formations which have a pressure gradient greater than that of a normal salt water gradient (1.05bar/10m). Abnormally pressured reservoirs can be caused by: − Closed reservoirs which do not outcrop at surface. − Formations under water flood.

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Equipment failure. Well control equipment failure is a primary cause of kicks becoming blowouts. In addition to normal maintenance the following should also be considered: − Extra care during cold weather. − Abrasion due to high mud solids. − Plugging from unconsolidated formations.

− Wear from previous well control operations. 4.1.2 Indications •

Primary warning signs. The primary warning signs are a direct indication that a kick may be occurring. Drilling operations should be suspended until the cause of the warning sign has been determined. Primary warning signs are as follows: − Pit gain or loss. A pit gain or loss is an indication of a change in hydrostatic pressure. A gain indicates that formation fluids have entered the wellbore. If a loss has occurred, the hydrostatic pressure may be reduced enough to allow an influx of formation fluids. − Drilling break. A drilling break is often an indication that a porous formation has been penetrated. If the formation is overpressurized a kick can occur. Always treat unexpected drilling breaks with caution. − Lost circulation. If lost circulation occurs, the hydrostatic pressure can easily be reduced enough to allow uphole formation fluids to enter the wellbore causing a kick. This is a difficult situation to control as the lost circulation must be cured prior to attempting conventional well control operations. − Incorrect hole fill. If the hole does not take the proper amount of fluid on a trip, it is possible that an influx of formation fluids has entered the wellbore. It is critical that proper hole fill records be kept to identify a formation fluid influx.

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Secondary warning signs. The secondary warning signs may be an indication that a kick is occurring. However, they are usually due to other mechanical problems. Always assume that a kick could be occurring until the cause of the warning sign has been determined. Secondary warning signs are as follows: − Variation in pump speed/pressure. If a kick is taken a reduction in hydrostatic pressure occurs. This may cause a slight decrease in pump pressure or a slight increase in pump speed. − Variation in string weight. If a kick is taken a reduction in hydrostatic pressure occurs. This may cause a slight decrease in the buoyant effect of the mud resulting in a slight increase in drillstring weight. − Mud contamination. Changes in mud properties may be an indication that formation fluids are entering the wellbore: • Gas Cutting. • Oil Flecking. • Density decrease from contamination due to water influx. • Changes to Mud Properties (i.e., pH, Viscosity, Gels, etc.) − Erratic table torque. A change in table torque may indicate that a transition zone is being penetrated. Caution should be exercised as a permeable high-pressure zone could exist below the transition zone. A change in table torque may also indicate a reduction in wellbore stability at the bit, due to invading fluids.

4.1.3 When to flow check To avoid a kick situation it is recommended that flow checks be conducted as follows: 1. While drilling (any warning sign). 2. Prior to tripping the drillstring.

3. While tripping (any warning sign). 4. Prior to having drill collars adjacent to the BOP's. 5. While out of the hole. 6. Extended rig shutdowns. •

Prior to tripping. If a high pressure zone has been penetrated prior to tripping, it is good practice to conduct a flow check after pulling the first 5 - 10 stands. If a well were to be swabbed in it can be detected early with this practice. A flow check should also be conducted 5 stands off the bottom when any unusual drilling conditions exist (i.e., tight hole).

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Extended rig shutdowns. If the rig is to be shut down for any extended period due to maintenance or repairs, the flow must be diverted to the trip tank and the hole fill pump turned on. This will allow for easy detection of a kick while crews are busy with repairs. An extended period should be considered to be anything longer than a 15 - 30 minute rig service.

4.1.4 Flow check procedures Flow check procedures must be performed quickly and efficiently to be effective. They must be a regular part of the day-to-day crew training done on the rig. If a flow is observed the well is to be shut in immediately. Flow check procedures are as follows: •

While drilling. 1. Call alert. 2. Stop rotary. 3. Hoist kelly or top drive until tool joint is above floor. 4. Shut down pump. 5. Divert flow to trip tank and zero tank. 6. Monitor and record volumes for 5-10 min. 7. If well is flowing shut in immediately.

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While tripping. 1. Call alert. 2. Pick up until tool joint is above the floor. 3. Set slips and release elevators. 4. Install kelly cock in open position. 5. Close kelly cock. 6. Start pump and ensure that hole is full. 7. Shut down pump. 8. Divert flow to trip tank and zero tank. 9. Monitor and record volumes for 5-10 min. 10. If well is flowing, shut in immediately.

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While out of the hole. 1. Call alert. 2. Start pump and ensure that hole is full. 3. Shut down pump. 4. Divert flow to trip tank and zero tank. 5. Monitor and record volumes for 5-10 min. 6. If well is flowing, shut in immediately.

4.2 Well Control General Shut In Policy The well is to be shut in immediately if the wellbore is flowing. Company policy is to use a soft shut in unless enough shoe integrity is available to allow a hard shut-in. Under no circumstances is the maximum allowable casing pressure (MACP) to be exceeded. NOTE:

During winter operations it is Company policy to close the last valve to the degasser in the choke manifold to help prevent freezing. This allows the bleed-off and manifold lines to be pressurised to 2-5 bar with a 50/50 glycol/water mix. The valve must be opened prior to shutting in the well. A notice (shown below) to open the valve must be posted in the appropriate places.

WELL CONTROL PROCEDURES Note:

FOR ALL WELL CONTROL SITUATIONS WHILE DRILLING, WHILE TRIPPING OR WHILE OUT OF THE HOLE, ENSURE THAT THE VALVE TO THE DEGASSER IS OPENED

This notice is to be posted in the doghouse, manifold enclosed, Company man’s office and Rig Manager’s office.

4.3 Special Shut In Procedures To ensure that the wellbore can be shut in quickly and efficiently regular drills must be held with the crews. It is Company policy that the following times be met during a shut-in drill: •

One minute to have pipe set in slips.

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Three minutes to have the well shut in.

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Five minutes to be ready to circulate/strip/etc.

Detailed shut in procedures are described in the following sub sections.

4.3.1 Offshore bottom supported units. •

While drilling: 1. Call alert. 2. Stop rotary. 3. Hoist kelly or top drive until tool joint is above floor. 4. Stop pump. 5. WINTER: Open manifold valve to degasser. 6. Open HCR through open choke. 7. Close annular preventer. 8. Slowly close choke. Do Not exceed MACP. 9. Allow pressures to stabilise (10 minutes). 10. Read and record SICP, SIDPP and tank gain.

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While tripping: 1. Call alert. 2. Hoist until tool joint is above floor. 3. Set pipe in slips and release elevators. 4. WINTER: Open manifold valve to degasser. 5. Install kelly cock in open position. 6. Close kelly cock. 7. Open HCR through open choke. 8. Close annular preventer. 9. Slowly close choke. Do Not exceed MACP. 10. Pick up and make up kelly. 11. Open kelly cock. 12. Allow pressures to stabilise (10 minutes). 13. Read and record SICP, SIDPP and tank gain.

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Collars adjacent to BOP’s: 1. Position upper drill collar box above the table and set slips c/w dog collar. 2. WINTER: Open manifold valve to degasser. 3. Install kelly cock in open position.

4. Close kelly cock. 5. Open HCR through open choke. 6. Close annular preventer. 7. Anchor collars to floor with reverse collar clamps and cables or chains. 8. Slowly close choke. Do Not exceed MACP. 9. Pick up and make up kelly. 10. Open kelly cock. 11. Allow pressures to stabilise (10 minutes). 12. Read and record SICP, SIDPP and tank gain. NOTE: If only one stand of collars is remaining in the hole it may be advisable to pull the stand and treat the well as "Out of Hole". •

Out of hole: 1. Call alert. 2. WINTER: Open manifold valve to degasser. 3. Open HCR through open choke. 4. Close blind rams. 5. Slowly close choke. Do Not exceed MACP. 6. Allow pressures to stabilise (10 minutes). 7. Read and record SICP and tank gain.

4.3.2 Floating unit (drillstring compensator operational). •

While drilling: 1. Call alert. 2. Stop rotary. 3. Hoist kelly until tool joint is above floor at the predetermined position for landing string on rams. 4. Stop pump. 5. WINTER: Open manifold valve to degasser. 6. Open HCR through open choke. 7. Close annular preventer. 8. Slowly close choke. Do Not exceed MACP. 9. Allow pressures to stabilise (10 minutes). 10. Close the uppermost rams (not variable bore rams). 11. Land string on rams. 12. Open annular preventer. 13. Set compensator in mid-stroke position. 14. Lock rams. 15. Read and record SICP, SIDPP and tank gain.

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While tripping: 1. Call alert. 2. Hoist until tool joint is above floor at the predetermined position for loading string on rams. 3. Set pipe in slips and release elevators. 4. WINTER: Open manifold valve to degasser. 5. Install kelly cock in open position. 6. Close kelly cock. 7. Open HCR through open choke. 8. Close annular preventer. 9. Slowly close choke. Do Not exceed MACP. 10. Pick up hang joint and make up kelly or top drive. 11. Strip hang joint through annular preventer to landing position. 12. Close the uppermost rams (not variable bore rams). 13. Land string on rams.

14. Open annular preventer. 15. Set compensator in mid-stroke position. 16. Lock rams. 17. Open kelly cock. 18. Allow pressures to stabilise (10 minutes). 19. Read and record SICP, SIDPP and tank gain. •

Collars adjacent to BOP’s: 1. Position upper drill collar box above the table and set slips c/w dog collar. 2. WINTER: Open manifold valve to degasser. 3. Install kelly cock in open position. 4. Close kelly cock. 5. Open HCR through open choke. 6. Close annular preventer. 7. Anchor collars to floor with reverse collar clamps and cables or chains. 8. Slowly close choke. Do Not exceed MACP. 9. Pick up hang joint and make up kelly or top drive. 10. Remove anchor collar clamps, chains, etc. 11. Strip hang joint through annular preventer to landing position. 12. Close the uppermost rams (not variable rams). 13. Land string on rams. 14. Open annular preventer. 15. Set compensator in mid-stroke position. 16. Lock rams. 17. Open kelly cock. 18. Allow pressures to stabilise (10 minutes). 19. Read and record SICP, SIDPP and tank gain. NOTE: If only one stand of collars is remaining in the hole it may be advisable to pull the stand and treat the well as "Out-of-Hole".

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Out of hole: 1. Call alert. 2. WINTER: Open manifold valve to degasser. 3. Open HCR through open choke. 4. Close blind rams. 5. Slowly close choke. Do Not exceed MACP.

6. Allow pressures to stabilise (10 minutes). 7. Read and record SICP and tank gain. 4.3.3 Floating unit (drillstring compensator non-operational). •

While drilling: 1. Call alert. 2. Stop rotary. 3. Hoist kelly until tool joint is above floor at the predetermined position for landing string on rams. 4. Stop pump. 5. WINTER: Open manifold valve to degasser. 6. Open HCR through open choke. 7. Close annular preventer. 8. Slowly close choke. Do Not exceed MACP. 9. Set pipe in slips. 10. Close lower kelly cock and bleed off kelly. 11. Remove kelly or top drive. 12. Pick up and make up drillpipe single and circulating head. 13. Pressure test circulating head. 14. Rig in compensator. 15. Open lower kelly cock. 16. Close uppermost rams (not variable rams). 17. Pick up string and remove slips. 18. Land string on uppermost rams 19. Open annular preventer. 20. Lock rams. 21. Allow pressures to stabilise (10 minutes). 22. Read and record SICP, SIDPP and tank gain.

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While tripping: 1. Call alert. 2. Hoist until tool joint is above floor at the predetermined position for loading string on rams. 3. Set pipe in slips and release elevators. 4. WINTER: Open manifold valve to degasser. 5. Install kelly cock in open position.

6. Close kelly cock. 7. Open HCR through open choke. 8. Close annular preventer. 9. Slowly close choke. Do Not exceed MACP. 10. Pick up and make up drillpipe single and circulating head. 11. Pressure test circulating head. 12. Rig in compensator. 13. Open kelly cock. 14. Close uppermost rams (not variable rams). 15. Pick up string and remove slips. 16. Land string on uppermost rams. 17. Open annular preventer. 18. Lock rams. 19. Allow pressures to stabilise (10 minutes). 20. Read and record SICP, SIDPP and tank gain.

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Collars adjacent to BOP’s: 1. Position upper drill collar box above the table and set slips c/w dog collar. 2. WINTER: Open manifold valve to degasser. 3. Install kelly cock in open position. 4. Close kelly cock. 5. Open HCR through open choke. 6. Close annular preventer. 7. Anchor collars to floor with reverse collar clamps and cables or chains. 8. Slowly close choke. Do Not exceed MACP. 9. Pick up and make up drillpipe single and circulating head. 10. Pressure test circulating head. 11. Remove anchor collar clamps, chains, etc. 12. Strip hang joint through annular preventer to landing position. 13. Close the uppermost rams (not variable rams). 14. Land string on rams. 15. Open annular preventer.

16. Set compensator in midstroke position. 17. Lock rams. 18. Open kelly cock. 19. Allow pressures to stabilise (10 minutes). 20. Read and record SICP, SIDPP and tank gain. NOTE: If only one stand of collars is remaining in the hole it may be advisable to pull the stand and treat the well as "Out-of-Hole". •

Out of hole: 1. Call alert. 2. WINTER: Open manifold valve to degasser. 3. Open HCR through open choke. 4. Close blind rams. 5. Slowly close choke. Do Not exceed MACP. 6. Allow pressures to stabilise (10 minutes). 7. Read and record SICP and tank gain.

4.4 Drilling Well Control Methods Most kicks occur while hoisting the drillstring in normally pressured areas. Control is generally lost through failure to observe the warning signs and to initiate proper well control procedures. A complete knowledge of pressure fundamentals is necessary for proper well control. The recognised methods of well control are the: 1. Concurrent Method. 2. Low Choke Method. 3. Top Kill Method. 4. Driller’s Method. 5. Wait and Weight Method. 6. Bullhead Method. The basic underlying principle in all well control methods is to "maintain bottomhole pressure at a value equal to or slightly above formation pressure." Failure to recognise specific situations can result in additional pressure being exerted on the formation and the casing seat. Prior to selecting a particular method of well control, the Company Representative should consider the following variables affecting each method: •

Depth of casing seat in relation to total depth.

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Maximum allowable casing pressure.

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Amount of barite on location.

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Size of kick.

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Time required to circulate out invading fluid.

•

Possible lost circulation zones.

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Position of drillstring at time of kick.

4.4.1 Concurrent method. Since most kicks require only a small density increase, this method is usually the fastest means by which to kill a well safely. Company requires that enough barite be stockpiled on location to allow mixing at one sack/min. until more barite is available. A minimum of 50 tonnes is required. Prior to completing the well control worksheet, isolate as many mud tanks as possible by bypassing down the mud ditch, making the active mud system as small as practical, thus minimising the required mixing times. The calculations required to allow the kick to be circulated out and the well killed can be done graphically or manually. CAUTION: Care must be taken to ensure that the proper graph is used. Graphs exist for mud densities of 1.0-1.3 S.G. and mud densities of 1.3-1.6 S.G. •

Information Required. To use the well control nomograph properly the following information is required: − − − − − −

Reduced Speed Pump Pressure previously recorded: RSPP (bar) Stabilised Shut-In Drillpipe Pressure: SIDPP (bar) True Vertical Depth: (m) Reduced Speed Pump Rate previously recorded: RSPR (m3/min) Mud Density: (S.G.) Maximum Allowable Casing Pressure previously recorded: MACP (bar) NOTE: The Initial Circulation Pressure (ICP) and Final Circulating Pressure (FCP) DO NOT INCLUDE ANY OVERKILL.

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Graphical mixing rate calculations (see Figures 2.1 and 2.2 *units=kPa and kg/m3). NOTE: Graphical Well Control Worksheets, see form 2.1 at the back of this section.

One Circulation STEP 1 Plot the reduced speed pump pressure (RSPP in bar previously recorded) on the vertical RSPP line. STEP 2 Plot the stabilised shut-in drillpipe pressure (SIDPP) on the left hand axis of the lower graph. Join the RSPP and SIDPP points with a straight line. From this line the initial circulating pressure (ICP in bar) can be read from the intersection with the vertical ICP line. STEP 3 From point 2 (SIDPP) draw a horizontal line to the right until it intersects with the line representing the present true vertical depth of the well. If a vertical line is projected downward from this point the density increase required to kill the well can be read on the lower graph’s horizontal axis. This density increase required to kill the well does not have any overkill built into it. STEP 4 From the intersection with the well depth line (Point 3) project a vertical line upwards until it intersects the previously recorded speed pump rate line (RSPR in m3/min.) on the upper graph. STEP 5 From point 4 (intersection with the RSPR), project a horizontal line to the left until it intersects with the left axis of the upper graph. From this intersection point the barite mix rate (sxs/min), required to kill the well in one circulation, can be read. The density required to kill the well (S.G.) can be determined by adding the density increase required to kill the well to the original mud density. STEP 6 If the required mix rate to kill the well is less than 1sx/min., or the rig is capable of mixing at greater than 1sx/min., then project a vertical line downward from the original Point 4 until it intersects with the well depth line. When the required barite mix rate to kill the well is less than 1sx/min. (40 kg/sx), Point 6 will be the same as the original Point 3. STEP 7 From Point 6 project a horizontal line to the left until it intersects with the vertical Delta P line. STEP 8 From Point 7 draw a straight line through the intersection on the ICP line. Continue to project this line until it intersects with the vertical final circulating pressure (FCP) line on the nomograph. The final circulating pressure (FCP in bar) can be recorded from this point (Point 8). NOTE: If the required mix rate is greater than 1sx/min. or greater than the rig capacity, then the well will require more than one circulation to kill. Immediately begin mixing 1sx/min. at the previously plotted ICP and RSPR.

Two Circulations Required STEP 9 From Point 4 if a line is projected horizontally to the left, the required barite mix rate (sxs/min.) to kill the well in one circulation can be read from the left-hand axis of the upper graph (Point 5).

When the required mixing rate to kill the well is greater than the mixing capability of the rig (i.e., >1sx/min.) then the well will require more than one circulation to kill. Immediately start mixing at 1sx/min. at the previously plotted ICP and RSPR. From point 4 follow the RSPR line back until it intersects with the horizontal 1sx/min mixing rate line (Point 6). From Point 6 project a vertical line downward until it intersects with the well depth line on the lower graph (Point 7). NOTE: It is Company policy that all rigs working for the Company are capable of mixing barite at a minimum rate of 1sx/min. STEP 10 From Point 7 project a horizontal line to the left until it intersects with the vertical Delta P line on the nomograph. NOTE: From Point 7 the density increase (S.G.) which will be achieved on this circulation can be read by projecting a vertical line down to the horizontal axis of the lower graph. STEP 11 From Point 8 project a line through the intersection of the vertical ICP line on the nomograph. STEP 12 Continue projecting the straight line from Point 9 until it intersects with the vertical final circulating pressure (FCP) line on the nomograph (Point 10). The FCP (bar) at the end of this circulation can be read from this point. At the end of this circulation the well should be shut in and the pressure recorded again. The nomograph must be filled out again and another circulation must be performed. This process must be repeated until the well can be killed with a circulation requiring 1sx/min. or less of barite. NOTE: During this circulation the ICP must be gradually reduced to the FCP, as the new density mud is circulated from the surface to the bit. From a practical standpoint there is usually very little difference between the ICP and FCP. As long as minimal overkill is being used (i.e., 7bar) the entire circulation can be made at the ICP. If there is more than a 5bar difference between the calculated ICP and FCP, then the circulating pressures should be adjusted as above.

Figure 4.1 Well control worksheets (steps 1 through 4)

Figure 4.2 Well control worksheets (steps 4 through 8) •

Well control procedure graph (see Figure 2.3).

STEP 1 1. Plot the initial circulating pressure (ICP in bar obtained from the well control nomograph or calculated manually) on the left-hand axis of the graph. 2. Plot the final circulating pressure (FCP in bar obtained from the well control nomograph or calculated manually) at the time/strokes to circulate at the reducedspeed pump rate (RSPR in m3/min.) from surface to the bit. 3. Join the ICP and FCP points with a straight line. 4. Crack open the choke. Start the pump and bring it up to the RSPR. Maintain constant casing pressure until the pump pressure has stabilised. Adjust the choke until the drillpipe pressure is at the plotted ICP. Start mixing barite at the required mix rate (sxs/min.). STEP 2 Circulate the kill density mud from the surface to the bit. Slowly reduce the drillpipe pressure from the ICP to the FCP. NOTE: If there is not a great deal of difference between the ICP and FCP (i.e., <5bar) then it is acceptable to circulate the kill density mud to the bit by holding the drillpipe pressure constant at the ICP. If there is a large difference between the ICP and FCP, then circulate the kill density mud to the bit in 5bar increments, as shown in the well kill procedure example. The ICP and FCP which are obtained from the well control nomograph or manual calculations do not include any overkill. Approximately 7-14bar in the overkill margin should be added to the calculated values when plotting the circulation pressures to be followed during the well control operation. STEP 3 1. Once the kill density mud is at the bit, hold the drillpipe pressure constant at the FCP until the kill density mud reaches the surface. Once the kill density mud reaches surface, the casing pressure should be equal to the amount of overkill being used, if the well was capable of being killed in one circulation (i.e., a mixing rate of <1sx/min. was required). 2. Stop the pump and allow the overkill to bleed off. Shut in the well. Both the drill pipe and casing pressures should read zero pressure. NOTE: If there is pressure remaining after shutting the well in and the drillpipe pressure and casing pressure are equal, it may be due to trapped pressure in the wellbore during the shut in. Bleed off the pressure and shut in the well again. If more than one circulation is required to kill the well then the SIDPP and SICP must be recorded again, and the well control problem solved for another circulation.

Figure 4.3 Modified concurrent method Manual Well Kill Calculations. Although the graphical method of determining the required barite mixing rate (40kg sxs/min.) is less complicated, there may be situations where more accuracy is required or a check on the graphical solution is desired. The following steps are required to solve the mixing rate required to kill the well. STEP 1 Calculate the circulating volume/time in minutes and strokes. Calculate the circulating volume and time (strokes). The volume/strokes must be segregated into 3 components: − Surface to bit (based on measured depth) − Bit to surface (based on measured depth) − Surface tank volume 1. Surface to Bit: DP capacity (m3/m) x length (m) + Collar capacity (m3/m) x length (m) = Volume surface to bit (m3) Strokes = Volume (m3) Pump Capacity (m3/stroke) 2. Bit to Surface (Annulus): Annular Capacity Collars/OH (m3/m) x length (m) + Annular Capacity DP/OH (m3/m) x length (m) + Annular Capacity DP/Csg (m3/m) x length (m) = Volume bit to surface (m3) Strokes

=

Volume (m3) Pump Capacity (m3/stroke)

3. Surface Tanks: Only use the active tank volume (m3). Do not include any by-passed tank compartments. Strokes

=

Volume (m3) Pump Capacity (m3/stroke)

Circulating Volume: Volume Surface to Bit (m3) + Volume Bit to Surface (m3) + Surface Tank Volume (m3) = Circulating Volume (m3) Circulating Time: Circ. Time (min.) = Circulating Vol. (m3) RSPR (m3/min.) where RSPR = Reduced Speed Pump Rate Circ. Time (strokes)=

Circulating Vol. (m3) Pump Capacity (m3/stroke)

STEP 2 Calculate the density increase necessary to kill the well in one circulation. The density increase (DI) required to kill the well can be found by utilising the SIDPP. This DI does not include any excess. Once the well has been killed, additional barite should be added to provide a 14bar overbalance while drilling. DI (S.G.) =

where:

SIDPP 0.1 x DI

DI SIDPP TVD

= Density increase to kill well (S.G.) = Shut In Drillpipe Pressure (bar) = True vertical depth of well (m)

STEP 3 Calculate the barite mixing rate to kill the well in one circulation.

The barite mixing rate can be determined as follows: 1. Barite Required: Barite Required (kg/m3)=

where:

4.25 (S.G) x DI (S.G.) 4.25 (S.G.) - NMD(S.G.)

Barite Required (kg/m3) = Barite required per 1m3 of circulating volume to kill the well 4.25 S.G.

= Density of barite

DI (S.G.)

= Density increase to kill well

NMD (S.G.)

= New mud density to kill

2. Total Barite Required (TBR): Barite Required (kg/m3) x Circulating Volume (m3)=Total Barite Required (kg) 3. Total Number of Barite Sacks Required: # Sacks = TBR (kg) 40 kg/sack 4. Barite Mix Rate (sxs/min.): Mix Rate (sxs/min.) = #Sacks Circulation Time (min.) STEP 4 If the mixing rate to kill the well is greater than 1sx/min. or the rig mixing capability, then calculate the density increase achieved with a circulation at 1sx/min. When the mixing rate required to kill the well is greater than 1sx/min. or the rig's mixing capability, then more than one circulation will be required to kill the well. In this case the density increase that will be achieved with the present circulation at 1sx/min. or the rig's mixing capability will be required: Density Increase (DI in S.G.): DI =

where:

40kg/sack x MR x (4.25 S.G. - MD) (4.25 S.G. x RSPR) - (40kg/sack x MR) DI MR MD

= Density increase in S.G. that will be achieved this circulation. = Barite mix rate in sacks/minute = Mud density in S.G. at the beginning of the present circulation. RSPR = Reduced speed pump rate previously recorded (m3/min.)

NOTE: The above calculation has assumed 40kg sacks of barite. If the sack size is different from this then the proper sack weight must be used. In addition, the density of barite has been assumed to be 4250 kg/m3. STEP 5 Calculate the ICP and FCP. The calculation of the initial circulating pressure (ICP in bar) and the final circulating pressure (FCP in bar) is dependent upon whether or not the well can be killed in one circulation or not. 1. Mix Rate of 1sx/min. or less (1 circulation to kill): ICP = SIDPP + RSPP FCP = RSPP x NMD OMD 2. Mix Rate of 1sx/min. (more than 1 circulation required to kill the well):

ICP = (SIDPP + RSPP) x OMD NMD FCP = RSPP x NMD + [( KMD-NMD)xLx9.81] OMD where : SIDPP = Stabilised shut-in drillpipe pressure (bar) RSPP = Previously recorded reduced speed pump pressure (bar) NMD = New mud density at the end of present circulation (S.G.) OMD = Original mud density at the start of present circulation (S.G.) KMD = Mud density required to kill the well (S.G.) L = True vertical depth of the well (m) NOTE: The above calculations do not include any overkill. Approximately 7-14bar of overkill should be held on the choke while circulating out the kick to prevent an influx of formation fluids during well control operations. STEP 6 Prepare a well control procedure graph as shown in figure 2.3. It is best to prepare the graph without any overkill included in the actual pressure line. The overkill should be shown on the stepped down pressures that the driller will actually be holding on the choke. Complete the well control worksheet and control log at the back of this section (Forms 2.2 and 2.3).

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Crew Positions. NOTE: The listed crew positions are applicable to alternate methods of well control. Driller - Controls the choke at the remote station on the floor. Ensures valve to degasser is open. Assistant Driller - Assists the driller. Derrickhand - Mixes barite as required at mixing station. Floorhand 1 and 2 - Assists the derrickhand. Rig Superintendent/Toolpusher - Ensures that all the crew members are performing their duties as required. Ensures that all required equipment is operating properly and any required standby equipment is available. Company Representative - Monitors all rig operations to ensure that well kill plan is carried out correctly. NOTE: Only essential personnel are to be present on the drilling floor.

4.4.2 Low choke method The low choke method of well control is usually the only method available when the MACP has been reached while circulating out a kick, and the gas bubble has not yet reached the casing shoe. This method entails bringing the pump up to full speed and mixing barite as fast as the rig's mixing system is capable (Do Not exceed 2sxs/min.). A complete circulation

is performed and the well is shut in again to determine if the kick can be circulated out with conventional methods. Where: The Maximum Allowable Casing Pressure (MACP) is the surface pressure (bar) at which the casing shoe will break down with the original mud density in the annulus. The MACP must not be exceeded. Several items can assist in ensuring that the casing shoe is not broken down, resulting in an underground blowout: •

If the kick consists of a gas bubble, once the gas bubble has reached the casing shoe no further increase in pressure at the casing shoe is possible. Thus, the MACP limits do not apply once a gas kick has reached the casing shoe. This phenomenon is due to the fact that high density mud is now being replaced by light density gas in casing annulus.

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If the MACP limits are close to being reached the overkill can be slowly bled off to buy more time while circulating out a kick. This may provide enough time to allow a gas bubble to reach the casing shoe.

4.4.3 Top kill method The top kill method of well control is frequently the only method available to kill a well when there is no pipe in the hole. The method entails mixing up high density mud and pumping it into the annulus until the MACP is reached. The heavier mud is allowed to fall and some casing pressure is bled off to allow the procedure to be repeated. This process is very time consuming and may take days to complete. Usually the procedure is only used until the shut-in pressure is reduced enough to allow the drillpipe to be stripped or snubbed to bottom. Special considerations when using this method include: •

Depth of casing seat.

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Maximum allowable casing pressure versus shut-in pressure.

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Depth of kicking zone.

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Fracture gradient of the zones above the kicking zone.

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Hole stability.

Well control procedure. 1. Shut in well. Read and record SICP and pit gain. 2. Open last valve in manifold to the degasser (winter operations). 3. Mix some high density mud (approximately 500 kg/m3 above original mud density). 4. Open the kill spool valves and pump a small volume of high-density mud (HDM) through the kill line until the MACP is reached. Ensure that the check valve on the kill spool is not leaking and allowing pressure to be bled back through the pump. 5. Hold the casing pressure constant at the MACP for 10-15 minutes to allow the heavier mud to fall. Bleed off a small amount of pressure through the choke (5-10bar). 6. Repeat steps 4 and 5 until the shut in pressure has been reduced sufficiently to allow the drillstring to be stripped or snubbed into the well.

4.4.4 Driller’s method The Driller’s method of well control utilises two primary steps to circulate out a kick and kill a well. In the first step the kick is circulated out while holding the bottomhole pressure constant. This allows the invading fluids to be circulated out of the wellbore without allowing any further influx of formation fluids. In the second step the well is killed by mixing kill density mud and circulating the wellbore over to it while again holding the bottomhole pressure constant. The two steps are performed as follows: 1. Circulate out the kick with constant bottomhole pressure. 1. Read and record the SIDPP, SICP and pit gain. 2. Open the last valve in the manifold building to the degasser (winter operations). 3. Slowly crack open the choke and bring the pump up to the previously recorded RSPR while holding the casing pressure constant at the previously recorded SICP + Overkill using the choke. 4. Once the pump is running smoothly read and record the drillpipe circulating pressure. 5. Using the choke hold the above drillpipe pressure constant until all invading fluids have been circulated from the wellbore. Always monitor the casing pressure while circulating out the kick. Do Not exceed the MACP. 6. Check all indicators that the kick has been circulated out. 7. Shut in the well and re-record the SIDPP, SICP and tank volume. 2. Circulate the wellbore to kill density mud with constant bottomhole pressure. 1. Calculate a new RSPP due to higher friction losses which will be experienced with the increased kill mud density. 2. Calculate the density increase and the amount of barite required to kill the well. Mix kill mud density. 3. Slowly crack open the choke and start the pump at the RSPR. Hold the SICP + overkill constant until the pump is running smoothly. 4. Using the choke, hold the casing pressure constant at the above pressure until the kill mud density reaches the bit. Read and record the drillpipe pressure at this point. 5. Using the choke hold the casing pressure constant at the above pressure until the kill mud density reaches the bit. Read and record the drillpipe pressure at this point. 6. Holding the drillpipe pressure constant at the above pressure, circulate the kill mud density to surface. 7. Stop the pump and shut in the well. Re-record the SIDPP and SICP. They should read zero. 4.4.5 Wait and weight method The wait and weight method of well control is an alternative method which can be used when either deep surface casing or intermediate casing is in place. The larger amount of casing is necessary as considerable casing shoe pressures are experienced due to gas

migration while mixing the kill mud density. If high density mud has already been pre-mixed this method of well control can be used in any wellbore configuration. The wait and weight method allows the well to be killed in one circulation. If the kill mud density has been pre-mixed prior to taking on a kick, this method provides the lowest equivalent casing shoe pressures while killing the well. Well control procedure. 1. Shut well in. Read and record the SIDPP, SICP and pit gain. 2. Calculate the mud density and amount of barite required to kill the well and mix a sufficient volume of kill mud density to circulate over the entire well. 3. Open last valve in manifold to degasser (winter operations). Slowly crack open the choke and start the pump at the previously recorded RSPR. Hold the casing pressure constant at the SICP + Overkill until the pump is running smoothly. Slowly adjust the drillpipe pressure from the ICP to the FCP as the kill mud density is circulated from surface to the bit. The graphical well control sheets can also be used to prepare the Wait and Weight Method pumping schedule. 4. Once the kill mud density reaches the bit, hold the drillpipe pressure constant until the kill mud density reaches the surface. Do not exceed the MACP. Check all indicators that the kick has been circulated out. Shut in the well and re-record the SIDPP, SICP and tank volume. The SIDPP and SICP should be equal to zero and the tank volume should have returned to normal. 4.4.6 Bullhead method The decision to use the bullhead method should be considered very carefully. It has the potential of damaging the reservoir, breaking down uphole formations and degrading the hole stability. In general the bullhead method simply involves pumping the kick directly back into the kicking formation by pumping down the annulus. Bullheading should only be considered on deep wells with the following characteristics: •

Intermediate casing has been set and no weak formations exist between the shoe and the kicking formation.

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The wellbore is very stable. Preferably the wellbore should consist primarily of limestones and dolomites.

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The formation being bullheaded into is not a potential reservoir or the reservoir will not be damaged beyond repair by the introduction of whole drilling mud.

Well control procedure: 1. Shut in well and record the SIDPP, SICP and pit gain. 2. Open kill spool valves and begin pumping kill density mud down the annulus. Typically this will not be possible without exceeding the MACP, thus the wellbore will be fractured. Displace the entire annulus over to kill mud density. 3. Close the kill spool valves and pump kill mud density down the drillpipe. 4. Shut in the well and allow the pressures to stabilise for a minimum of one hour. This will allow pressure caused by supercharging the formation to bleed off into the formation. The pressures should bleed off to zero if the well has been killed.

NOTE: This method of well control can cause a great deal of damage to both the formation and the wellbore stability. It should only be used in very special situations after considering all other well control alternatives. The advantages and disadvantages of the various well kill methods are listed in Table 2.1.

Table 4.1 Advantages and disadvantages of well kill methods Method Driller's

Wait and Weight

Advantages Simplest to teach. Very few calculations. Could circulate out high pressure/low volume gas pocket. Lowest casing pressure. Lowest equivalent circulating density at casing seat. Avoid potential lost circulation during well killing procedures

Disadvantages Higher casing pressure. Higher equivalent circulating densities at casing seat. Requires minimum of two circulations. Requires longest non-circulating time while mixing heavy mud. Pipe could stick during non-circulating period in shale or anhydrite sections. Requires more calculations.

4.5 Completion Well Control Methods The objective of killing a well has been achieved when the formation fluids have been circulated from the wellbore and replaced with a completion/workover fluid which exerts a hydrostatic pressure that is in excess of the formation pressure. NOTE: An overbalance of 14bar is recommended. The preferred method of killing a well is to bullhead the influx back into the source. The Company Representative must be consulted prior to proceeding with well killing operations. There are various methods to be utilised in order to kill a well. They are: •

Normal circulation (down the tubing). This method is probably the most widely used in the industry when killing flowing wells or wells with light fluid or gas in the annulus. Surface equipment employed in these procedures include a pump and a choke to hold back pressure while circulating. Summarised below are the procedures for this method: 1. Bleed off any gas head in wells containing liquids. 2. Re-check and record SITP and SICP. 3. Open the choke, start the pump, and bring up to normal circulating speed. 4. Adjust the choke, holding the casing pressure (SICP value) constant until the kill fluid reaches the bottom of the tubing. 5. After the kill fluid reaches the bottom of the tubing string adjust the choke to hold the tubing pressure constant until the kill fluid reaches the surface. 6. Stop the pump and shut the well in. 7. SITP and SICP should be zero. When bleeding off any gas head that contains hydrogen sulphide (H2S), ensure that the gas is routed through proper separation and flare equipment.

•

Reverse circulation (down the annulus). This method is probably most widely used in the industry when killing pumping wells or wells with a packer and packer fluids in place. Reverse circulation is normally used when a packer is in place and the annulus is filled with an inhibited packer fluid. Either a sliding sleeve is opened, or the tubing is perforated to provide access to the tubing string. Normally, the packer fluid density is sufficient to balance formation pressure, and the kill fluid density will closely approximate the packer fluid density. If this is not the case, two circulations will be required to kill the well: one circulation to displace the tubing to completion fluid, followed by the second, displacing the annulus and tubing to kill fluid. The procedures shown below assume the annulus fluid is of sufficient density to kill the well when contact has been established between the tubing and casing: 1. Bleed off any gas head in wells containing liquids. 2. Re-check SITP and SICP. 3. Crack the choke and bring pump to a predetermined speed. 4. Hold the tubing pressure (SITP value) constant by adjusting the choke. 5. After the pump reaches a constant speed, hold the casing pressure constant until the packer fluid has been circulated out. 6. Stop the pump and shut the well in. 7. SITP and SICP should be zero. When bleeding off any gas head containing hydrogen sulphide (H2S), ensure the gas is routed through proper separation and flare equipment. Should the packer fluid density be less than required to kill the well, the above procedures should be followed until the tubing volume has been displaced from the annulus with a similar density fluid. At this point commence pumping kill fluid holding the tubing pressure constant until kill fluid reaches the sliding sleeve or tubing perforations. The casing pressure would then be held constant until kill fluid reaches the surface.

•

Bullheading is a term used to describe killing the well by forcing formation fluids back into the formation by pumping kill fluid down the tubing. Formation fluids often affect the feasibility of attempting to bullhead. Low viscosity fluids such as gas will flow back into the formation at a faster rate than oil or water. Gas will also have less tendency to plug the formation as it reverses the flow. Gas migration may have a serious effect upon bullheading operations. Gas migration is the upward movement of low-density fluids through high-density fluids. Factors affecting gas migration rates include: 1. Fluid densities and viscosities. 2. Hole geometry. 3. Influx size. Where low pump rates occur, the upward migration of gas may equal or exceed the downward fluid rate, negating the advantages of bullheading. In some cases, it may become necessary to increase viscosity to offset or slow down the gas migration rate.

Under some circumstances, back-up pressure may have to be applied to the casing annulus to prevent tubing burst. This generally is used if tubing pressure becomes excessive or the tubing integrity is questionable as a result of corrosion and erosion. Always ensure that casing burst limits are not exceeded. In high-pressure pumping, some operators favour a pressure relief valve installed on the tubinghead outlet. Should a tubing failure occur this prevents over-pressuring the casing. In some instances the rig pump may not be capable of operating at the required pressures; and may have to be replaced with a suitable high-pressure pump. NOTE: This method of well kill may not be used if the integrity of the wellbore is in question, i.e., corroded basing, uphole perforations, etc. Listed below are suggested procedures for the bullheading method: 1. Calculate the maximum allowed surface-imposed pressure that will not exceed formation fracture gradient. 2. Determine the tubing/casing burst pressure and wellhead working pressure. 3. Calculate the tubing/casing annulus back-up pressure (if used). 4. Mix kill fluid to required density. 5. Slowly begin pumping kill fluid down the tubing following the pressure schedule. 6. Do not exceed formation fracture pressure unless instructed to do so. 7. Monitor tubing/casing pressures for any undesirable pressure build-up. 8. Pump kill fluid until the tubing is fully displaced. 9. Stop the pump and shut the well in. 10. SITP should be zero. •

Lubricate and bleed - this method is occasionally used for killing wells during workover operations. It involves alternately pumping a kill fluid into the tubing, allowing the kill fluid to fall, then bleeding off a volume of gas until kill fluid reaches the choke. As each volume of kill fluid is pumped into the tubing the SITP should decrease by a calculated value until the well is eventually killed. This method is often used for two reasons: 1. Where shut-in pressures approach the rated working pressure of the wellhead, or tubing and dynamic pumping pressure may exceed the limits, as in the case of bullheading. 2. The lubricate and bleed method can be used to either completely kill the well or lower the SITP to a value where other kill methods can be safely employed without exceeding rated limits. Another application of this method is where the wellbore or perforations are plugged, rendering bullheading useless. In this case, the well can be killed without necessitating the use of endless tubing or snubbing small diameter tubing. The lubricate and bleed method is often a very time-consuming process; another method may kill the well more quickly. Procedures:

1. Record the SITP and SICP. 2. Open the choke to flare, allowing gas to escape and momentarily reducing the SITP. 3. Close the choke and a valve downstream from the choke. 4. Slowly pump kill fluid until the pump pressure reaches the maximum allowable working pressure, or some predetermined pressure. 5. Stop the pump. 6. Wait for the fluid to drop in the tubing. Fluid full rate is calculated by the gas migration rate which is approximately 600m/hr. •

Lubricating plugs, i.e., tubing plugs, bridge plugs, packers with a plug in place, and backpressure valves. This method of killing a flowing well can be done safely with a lubricator in place. The type of equipment that can be run on wireline are tubing blanking plugs, plugged packers, and bridge plugs. Once the plug is in place, the tubing and/or casing is bled off. With the well dead, the kill fluid can be circulated to the wellbore. This method is most useful in the situation where a circulating string is not present (post perforating) and the tubing string is live. Fill well without tubing.

•

Snubbing in with endless tubing. Endless tubing is often used to kill a producing well. The method used is to circulate kill fluid down the endless tubing and up the production tubing or casing (tubingless completion). This method would be applicable in the situation where the production tubing is plugged, eliminating bullheading or tubingless completion. The procedures for killing a well using endless tubing are basically no different from procedures for the normal circulation method. Outlined below are the basic procedures for the endless tubing method (check with service company on tubing strength limit): 1. Rig in endless tubing unit, pressure test surface equipment, fill endless tubing with kill fluid. Ensure that a check valve is in place. 2. Bleed off any gas head in wells containing liquids. 3. Re-check SITP and SICP. 4. Pressure up endless tubing to SITP valve and open master valve. 5. RIH endless tubing. Note: Fill tubing every 600 m to prevent collapse, monitor SITP and bleed off, if necessary, pressure increase resulting from running the endless tubing (in oil-filled tubing strings, bleed off volume should be closely monitored to ensure proper volume is bled off). 6. After reaching desired depth, open the choke and bring pump up to desired speed. 7. Hold production tubing pressure (SITP value) constant by adjusting the choke. 8. After the pump reaches a constant speed, hold the endless tubing pressure constant until kill fluid reaches the surface. 9. Stop the pump and shut the well in. 10. Shut in endless tubing and production tubing pressure should be zero. 11. If well is dead, prepare to pull endless tubing. Open the choke and start the pump (minimum pump rate should equal the displacement of the endless tubing). 12. Adjust the choke to hold the overkill value constant on the production tubing. 13. Pull endless tubing.

14. After endless tubing is above master valve, stop the pump and shut the well in. 15. Check for pressure build-up on production tubing. If none is present, resume normal operations.

4.6 Tripping : Equipment, Procedures and Record Keeping. Studies have shown that historically 80% of all kicks occur while tripping. The majority of these are due to improper hole fill procedures.

1. All rigs are to be equipped with continuous hole fill systems. See Figure 2.4. •

The following describes the hole fill equipment: − Mud Can. All rigs working for the Company are to be equipped with a mud can which may be readily rigged up. The mud can is to be used on all wet trips to ensure that the proper hole fill volumes are being recorded. The mud can is to be rigged in so that all mud collected is diverted to the trip tank. This is usually accomplished by having a nipple on the flow line in which the mud can be connected to. − Flow Line. The flow line must be rigged up such that the flow can be diverted directly to the trip tank, thus by-passing the shakers. This allows the hole to be filled continuously while tripping.

Figure 4.4 Hole fill equipment set-up

− Continuous Hole Fill Pump. An independent hole fill pump is required. The only suction allowed is from the trip tank. The discharge of the pump is to be connected to the lower portion of the flow nipple, well below the flow line. It is good practice to have the inlet of the fill line located on the same side of the flow nipple as the flow line. This will help to prevent spillage and hole fill mud from going directly down the flow line and causing misleading hole fill readings. •

All trip tanks are to conform to Company specifications. − Trip Tank. The trip tank must be totally isolated from the main mud system (i.e. no common manifolds). A minimum useable volume of 3m2 is required. This size requirement results in a field level change of 1” equating to a volume change of 0.075m3. − Trip Tank Fill Pump. A pump which can fill the trip tank with mud from the main mud system must be available. The discharge from the pump must be above the fluid level in the trip tank. This will prevent the possibility of mud leaking back through the pump system and causing inaccuracies in the hole fill measurements while tripping. − Manual Tank Gauge. A manual float must be available in the trip tank. It must be rigged up such that the driller can read a 0.1m3 change in the trip tank volume. The trip tank gauge must be visible from the driller’s position. − PVT. The pit volume totalizer must have a separate probe which is dedicated to the trip tank (i.e., isolated from the main mud system). The PVT must have a mode switch which shows the trip tank volume only. A maximum spacing of 1/2” between probe pick-ups is allowed, however 1/4” is preferred due to the improved resolution.

•

A graphical trip record is to be kept for all trips out-of-hole. The graphical method is preferred as it quickly identifies trends, see Figure 2.5. − Drillpipe stands • Drillpipe stands are shown in 5 stand increments. Under no circumstances is a stand to exceed 30m for the purposes of calculating hole fill requirements. • Scale this axis of the graph in 5 stand increments to represent the total number of drillpipe stands that will be tripped. − BHA and heavyweight (Hevi Wt) • The actual fill volume for every stand must be plotted since the displacements are significantly higher than drillpipe. • A separate small graph should be prepared. − Theoretical dry-trip line • On the graph plot the total hole fill that would be required to fill the drillpipe for a dry-trip (collars and heavyweight should be plotted separately). Draw a straight line between the zero point and the theoretical fill point. This line represents the lower trend limit that should be expected if the hole is taking the correct amount of fill on a trip. If the actual hole fill required drops below this line, it is likely that a kick has occurred. Stop tripping immediately and perform a flow check. − 10% mud hold-up line • During a trip mud always sticks to the inner wall of the drillstring. The amount of sticking mud is usually in the range of 10%, however it varies with mud properties. Add 10% to the theoretical dry drillpipe displacement and plot another line. This line should closely follow the actual hole fill required during the trip.

Figure 4.5 Graphical trip sheets − Measured hole fill line • This line represents the actual hole fill that is required during the trip. It must be updated every 5 stands of drillpipe and every stand of heavyweight and drill collars. − Deviation • When a deviation from a straight line is observed, then either a kick has occurred or the wellbore is taking fluid. A deviation downward indicates an inflow from the wellbore while an upward deviation indicates that the wellbore is taking fluid. • Any deviation from the trend established should be considered to be a kick. Stop tripping immediately and perform a flow check. • As it is Company policy to use a weighted pill while tripping, there will appear to be a flow when the heavy pill reaches the drill collars. This is due to lengthening of the pill within the collars and the subsequent U-tube effect. − Hole fill (m3) − This column represents the actual hole fill required for every 5 stands of drillpipe and each stand of heavyweight or drill collars. This number is added to the previous cumulative hole fill to obtain the cumulative hole fill number to be plotted on the graph. Be sure to carry this number to the nearest 0.1m3. − Cumulative hole fill (m3) • This column represents the actual cumulative volume of fill that the hole has required to date. This is the number which is plotted on the graph to create the measured hole fill line. • This axis of the graph should be prepared after the theoretical hole fill for the drillpipe has been calculated. Make sure the graph is scaled in small enough increments that trip accuracy can be maintained.

NOTE: Graphical Trip Sheet form 2.4 at the back of this section. 2. To avoid a kick situation it is recommended that flow checks be conducted as follows: − Prior to pulling out of the hole. − While tripping (any warning sign). − Prior to having drill collars adjacent to the BOP’s. − While out of the hole. − During extended rig shutdowns. 3. A weighted pill should be pumped prior to tripping to enable pulling of dry pipe. This will minimise surface losses and improve hole fill volume. The size of the pill can be calculated as follows: Pill Volume = Drillpipe Capacity (m3/m) x 275 Barite Required = Pill Volume (m3) x 8 sacks /m3 4. A stripper rubber should be used on each trip out of the hole. This will ensure that the mud is removed from the outside of the drillpipe and is saved during a trip. When using automatic strippers its design must be configured such that the stripper can be split. This will allow the stripper to be removed from below the table in the advent of a well control problem. 5. If the tripping speeds are excessive a kick can be caused by swabbing in the well while tripping out. During trips into the wellbore surge pressures caused by excessive trip speeds can cause formation damage, lost circulation or hole instability. In addition to tripping speeds the following should also be considered before tripping: − Annular hole clearance. Is the hole tight? − Mud properties (Vis, PV, Gels, and YP*) − Is the bit balled? − Nozzle sizes. * An increase in yield point or plastic viscosity will increase the swabbing pressures. In general the following trip speeds should be adhered to: − 30 seconds per 28m stand (pipe in motion only) on conventional trips. − 60 seconds per 28m stand (pipe in motion only) while tripping against unstable shales, sour formations or high-pressure zones. − 60 seconds per 28m stand (pipe in motion only) while below intermediate casing and sour zones. 6. When tripping it is good practice to rotate the stand immediately above the collars/HW to a different position in the drillstring after each trip. This will help to distribute the wear and loading more evenly throughout the drillstring. It is also good practice to periodically lay down a single prior to tripping. This will cause different tool joints to be broken on the trip out, thus allowing more even wear of the tool joints and allowing re-doping of tool joints which have not been re-doped for some time.

4.7 Leak-Off Tests Shale Section Exposed. The surface casing must always be set deep enough that the shoe joint will be in a competent shale section. Sand and gravel sections must not be present immediately below the shoe as the ability to control a kick will be compromised. The same criteria should be followed for picking an intermediate casing point except that a dense limestone or dolomite

may be the only choices available for a casing seat. Do not set a shoe joint in a porous formation under any circumstances. After setting the casing it may be necessary to determine the pressure integrity of the formation below the casing shoe. A formation leak-off test (FLOT) should be performed when programmed and/or whenever required by regulatory bodies. Leak-off test procedures (Leak-off test form 2.5 at the back of this section). STEP 1 - DRILL OUT SHOE JOINT. 1. Drill approximately 5-10m of new hole below the casing shoe. 2. Pull back into the casing shoe. 3. Ensure that the hole is full. Stop pump. 4. Close Annular Preventer. STEP 2 - START PUMPING.

1. Using a high-pressure, low-volume pump, begin pumping at 4-8 l/min. Rig pumps are not suitable for this purpose. 2. Plot the pumping pressure versus volume pumped on the graph. If possible, the volume should be recorded for every 5 litres pumped. 3. If the leak-off test is being performed in an open hole, the pump rate will have to be increased. Start pumping at 10-20% of the RSPR and increase the pump rate in 25-50 l/min. increments until the desired leak-off pressure has been achieved. If the desired leak-off pressure has not been achieved at a pump rate of 50% of the RSPR, then consideration should be given to setting intermediate casing. A small cementer will likely be required to obtain the required rates and pressures. Record the volume versus pressure for every 25-50 litres pumped if possible (i.e., every 30 seconds). An open hole leak-off test should not require more than 30 minutes to complete. Typically 3-4 steps up in the pump rate will be required to obtain the desired leak-off pressure. Details of the open hole leak-off procedures are shown in the open hole example. STEP 3 - MONITOR LEAK-OFF.

1. Monitor the pumping pressure and volume. Plot for every 5 litres pumped if possible. 2. The leak-off point begins at the first deviation from a straight line. The pressure recorded at this point will be used to calculate the maximum allowable casing pressure which can be held at the surface during a well control situation. STEP 4 - STOP PUMPING.

1. Stop the pump as soon as the leak-off point has been reached. This will prevent the casing shoe from being fractured. 2. If a surface pressure equivalent to 2.2bar/10m has been reached without any deviation from a straight line, stop the pump. Any further increase in pressure will not accomplish anything. The open hole formations which will be drilled are not capable of holding more than 2.2bar/10m. 3. Do Not exceed 80% of the casing burst rating while performing a leak-off test. STEP 5 - CALCULATE MACP.

Using the pressure recorded at the leak-off point, the leak-off gradient, maximum allowable casing pressure (MACP) and the maximum equivalent mud density that can be held on the casing shoe can be determined: LOG (bar/10m) = Leak-Off Pressure + Hydrostatic 0.1 x TVDS Where: LOG

= Leak-Off Gradient at Csg Shoe (bar/10m) Hydrostatic = Hydrostatic Pressure at Casing Shoe (bar) True Vertical Depth of Csg Shoe = TVDS (m)

MACP (bar) = 1/10 TVDS x (LOG - W1) Where: W1 EMD (kg/m3) =

Where:

= Mud Gradient in use

LOG 0.981 EMD = Maximum equivalent mud density which can be held on the casing shoe (kg/m3)

Figures 2.6 through 2.11 provide typical examples of what may occur when evaluating the open hole fracture gradient. NOTE: Figures 2.6 through 2.11 give pressures in kPa (1kPa = 0.01bar).

Figure 4.6 Completed leak-off test (no leak-off)

Figure 4.7 Completed leak-off test (normal) Anticipated Leak-off Pressure (bar). When performing a leak-off test a line should always be drawn at the anticipated leak- off pressure. This will give an indication of when to stop the pump. The line is typically drawn at a pressure which equates to a gradient of 1.8bar-2.2bar/10m at the casing shoe. MACP (bar). A line should be drawn on the graph which represents the surface pressure required to obtain 2.2bar/10m at the casing shoe. This will be the maximum pressure which will be used during the leak-off and it will equate to the maximum allowable casing pressure. Exceeding this pressure during the leak-off test will not provide additional kick control as the formations which will be exposed in the open hole section will not be capable of holding more than 2.2bar/10m. This line is not to exceed 80% of the Surface casing burst rating. Stop Pumps. If it appears that the leak-off has occurred well below the anticipated pressure it may be due to filtration losses. Frequently, if the pump is stopped for a few minutes and then restarted, the leak-off test will proceed to the required pressure. If the leak-off occurs at the same pressure again it may be necessary to spot a gel pill over the shoe joint and repeat the test again.

Figure 4.8 Incomplete leak-off test (filtration losses)

Figure 4.9 Leak-off test (open hole) When performing an open hole test, higher pump rates are used. Begin the first stage of the test at 10-20% of the RSPR (25-50 l/min.) and pump until the first leak-off occurs. This will typically be well below the required leak-off pressure. Stop the pumps for a few minutes. Begin pumping the second stage of the test by increasing the pump rate by 25-50 l/min. (depending upon the initial leak-off pressure). Typically 3-4 stages will be required to achieve the required leak-off pressure. A leak-off should be achieved without exceeding 50% of the reduced-speed pump rate recorded on the drilling rig (25% is preferred). If more than 50% of the pump rate is required to overcome the leak-off rate, the ability to control the well while circulating out a kick is questionable. A small cementing unit is preferred for performing the open hole leak-off test. Continue increasing the pump rate in stages until a leak-off above the required leak-off pressure is achieved. This should be achieved without exceeding 50% of the previously recorded reduced-speed pump rate (25% is preferred). If more than 50% of the RSPR is required to overcome filtration losses, the ability to circulate out a well kick is questionable.

Figure 4.10 Completed leak-off test (casing shoe cement failure)

Figure 4.11 Extended leak-off test (formation fractured) Leak-Off Pressure. This is the applied surface pressure at which the plot of pressure versus volume pumped begins to deviate from a straight line. This pressure will be used to determine the maximum

allowable casing pressure (MACP) which can be held on the choke during a well kill operation. The pump must be shut down as soon as this deviation occurs to prevent fracturing down the casing shoe. If the leak-off has occurred at a value below 1.7bar/10m then there may not be sufficient casing shoe integrity to handle a kick. Spot a viscous gel pill over the shoe and attempt the leak-off test again. If the leak-off pressure does not increase on the second attempt it may be due to a casing shoe cement failure or an incompetent casing shoe formation. Often the shoe integrity can be improved by performing a bradenhead cement squeeze on the shoe joint.

4.8 Crew Training Crew training is ultimately the responsibility of the contractor or service company. However, it is still the responsibility of Company to provide a safe work environment and to ensure that safe work practices are being followed. The Company Representative is to ensure that all Company and Government safety procedures and regulations are being followed. Safety procedure meetings and/or drills are to be conducted prior to any difficult or nonroutine operation. These meetings and drills are to be recorded in a safety meeting minutes book and the tour book. BOP drills are to be conducted regularly to ensure that the crews are familiar with their responsibilities during a well shut-in. Blow out drills will be conducted prior to drilling out surface casing and by each crew every seven days thereafter. The Company requires that the following times are achieved during a well shut-in: •

1 minute to have the pipe set in the slips.

•

3 minutes to have the well shut in.

•

5 minutes to be ready to circulate/strip/etc.

These values are maximum times. It is anticipated that the crews should be capable of much faster times during normal shut-in situations. The daily BOP function test is a good time to conduct a BOP drill. In addition, BOP drills should be conducted at unexpected times to ensure that the crew is alert and proficient with shut-in procedures. NOTE: Blow Prevention Drill form 2.6 at the back of this section.

4.9 General Requirements 4.9.1 Surface casing wear prevention If the surface/intermediate casing becomes sufficiently worn, the ability to handle a well kick may be compromised. The following practices should be adopted to minimise surface/intermediate casing wear: •

Ensure that the rig is level prior to spudding and that the surface hole is drilled with a minimum of deviation.

•

Leave the surface casing centralised in slips while waiting on cement prior to cutoff.

•

If more than 14 days are required to drill a hole section, then a wear bushing is to be installed in the casing bowl.

•

A casing protector is to be installed on the saver sub.

•

Ensure that any hardbanding within a casing string has been previously worn smooth.

•

Any casing string which will be exposed to more than 30 days drilling is to have a multiarm calliper run prior to drilling out the casing shoe. This calliper will be used as the baseline casing wear measurement. A calliper must then be run every 30 days of drilling thereafter.

4.9.2 Casing wear, tool joint wear and drillpipe protectors On deep wells where there are significant doglegs, the use of drillpipe protectors inside the casing string should be considered. Never run new or rough hardbanding inside of a casing string. It should always be buried in open hole for a wear in period. Sand content in the mud can be extremely erosive. It should be maintained below 0.5%. 4.9.3 DST interval DST intervals will be limited to 20m. This is to prevent a significant reduction in hydrostatic when unseating a test tool following a gas test. Any alteration to this practice must be approved by the Company Drilling Manager for the area. 4.9.4 Production casing slip and seal assemblies Automatic slip and seal assemblies are to be used on all wells which have sufficient string weight to set the slips following cementing. The slips are to be set by dropping the slips through the BOP stack with wires. The only exceptions to this rule will be wells with small clearances between the slips and BOP bore or slant wells where there may be too much drag to drop the slips through the BOP's. In these cases the stack may be lifted to set the slips. Be absolutely sure that the well is under control prior to lifting the stack. 4.9.5 Drillpipe floats It is Company policy to use a drillpipe float. The float is to have a 1/4" hole drilled in the float to allow SIDPP to be read if a kick is taken. Considerations in running a float should include: •

Will it hamper other operations (i.e., coring)? Do Not run a float in this case.

•

If the well being drilled is sour then the spring mechanism on the float should be rated for sour service.

4.9.6 Casing changeovers Extra care must be taken when running casing. Be sure that the rig has a changeover available to allow the kelly cock to be used. It is not sufficient to only have the cementers change over when they arrive on location. It is good practice to have the kelly cock already made up to the changeover prior to running casing. A changeover is not required for running surface casing.

4.9.7 Stabbing valves and IBOP’s A stabbing valve and inside BOP valve (IBOP) with matching threads to the drillpipe, drill collars and kelly must be readily available. They must be stored in a warm place during winter operations. The kelly cock must be left in the open position and equipped with removable handles. The kelly cock opening wrench is to be stored with the valve. 4.9.8 BOP changeovers while running casing In general, the Company does not change over to the upper BOP rams casing rams as it usually compromises the well control operation more than the running of the casing. Any exceptions to this practice will be included in the drilling program or will be communicated to the field via the Drilling Manager. If a special situation is encountered where the Rig Superintendent/Toolpusher feels that it may be prudent to change the rams, it should be discussed with the Company Representative. If the BOP body is opened to changeover, the rams then the BOP door seals must be tested again. This is typically accomplished with a cup style tester on a joint of drill pipe. Do not exceed 80% of the casing burst rating or 50% of the annular BOP working pressure during the test (10 minutes). Be sure to monitor the hook loads while testing as the cross-sectional area of the cups may cause a significant hook load. It is not necessary to test the ram blocks if a thorough visual inspection has been performed.

4.9.9 Waste oil disposal In accordance with our established operating procedures in drilling and servicing operations, the Company requires that all waste oil resulting from these operations be collected in an adequate container and removed from the location to either an approved disposal site or reclamation facility.

Form 4.1 Graphical well control worksheet (page 1 of 4)

Form 4.2 Well control worksheet

Form 4.3 Well control log

Form 4.4 Graphical trip sheet

Form 4.5 Leak-off test

Form 4.6 Blowout prevention drill Contents

3. ENVIRONMENTAL CONSIDERATIONS ..........................................................................3.i 3.1 Introduction ................................................................................................................3.i 3.2 Chemicals Used in Drilling .........................................................................................3.i 3.2.1 General ............................................................................................................ 3.ii 3.2.2 Toxicity of drilling fluids ....................................................................................3.7 3.2.3 Testing and evaluation of drilling fluid chemicals ............................................ 3.vi 3.3 Waste Handling........................................................................................................ 3.vi 3.3.1 Introduction ..................................................................................................... 3.vi 3.3.2 Identification of waste streams.........................................................................3.8 3.3.3 Minimising of waste streams .......................................................................... 3.vii

ENVIRONMENTAL CONSIDERATIONS

4.10 Introduction The Company policy on environmental issues is for continuous environmental improvement with the ultimate goal being: • No negative impact from operation emissions, discharges or dumping of waste. In line with this policy rig personnel shall endeavour to: • Prevent all negative effects on the environment. • Not waste resources and energy. • Reduce residual waste products to a minimum and optimise re-use (recycling). • Prevent undesired concentrations of toxic substances in products, additives and waste. • Ensure responsible environmental care and behaviour by employees and contracted

personnel. Based on these considerations The Company strives to satisfy the public that every effort is made, within reasonable limits, to work in an environmentally responsible way. For further information on the environmental policy refer to the Company HSE manual.

3.2. Chemicals Used in Drilling 3.2.1.General A wide variety of chemicals are used in the mixing of drilling fluids and cements. A.

PACKED/PALLETIZED (MUD-) CHEMICALS (ALPHABETIC SEQUENCE)

Item

Product

001 002 003 004 Item

Aquamagic Baryte Bentonite Wyoming QS-2 Bentonite Product

005

Calcium Chloride Flakes 77/80% cacl. 2 Calcium Chloride Flakes 77/80% cacl. 2 Carbogel-N Carbomul Caustic Soda Pearls Cebodol-325 Cebodol-325 Cellophane CMC ehv tvg 40 Coat-B1400 Edelwit Ca(OH)2 Lime Fenoil AF-1103 (Defoamer) Grit (CaCo3) Fine 2-4 mm. Grit (CaCo3) Coarse 4-7 mm. Gypsum HEC Natrosol Kalium Chloride (Potassium) Kalium Chloride (Potassium) Kalium Hydroxide Prills (KOH) Kalium Jodide Magnesium Chloride Magnesium Chloride Mica Fine Mica Course Mikhart 0.35-0.7 Mikhart 0.5-1.5 Mikhart 130 Milguard Mudfiber Pipelax Salt Broxo Salt NCP Salt NCP Stabilose LV

006 007 008 009 010 011 012 013 014 015 016 017 018 019 020 021 022 023 024 025 026 027 028 029 030 031 032 033 034 035 036 037 038

Packing 25kg bags 25kg bags 25kg bags 25kg bags Packing 25kg bags big bags 25kg bags 55gal. dr. 25kg bags 25kg bags big bags (1 ton) 20kg bags 25kg bags 55gal. dr. 25kg bags 50kg drum 25kg bags 25kg bags 40kg bags 25kg bags 25kg bags big bags 50kg drum 50kg drum 25kg bags big bags 25kg bags 25kg bags 25kg bags 25kg bags 25kg bags 25kg bags 25kg bags 55gal. dr. 25kg bags 25kg bags big bags 25kg bags

039 040 Item 041 042 043 044 045 046 047 B)

Item 048 049 050 C)

Item 051 052 053 054 055

D)

Stabotemp HT Staflo Exlo Product Staflo R Starch (Flogcel) LV Starch (Flogcel) HV/TA Servodril CDM791 Sodium Bicarbonate (NaHC03) Walnuts XC-polymer (ex Kelzan)

25kg bags Packing 25kg bags 25kg bags 45kg drum 25kg bags 25kg bags 25kg bags

BULK (MUD-) CHEMICALS (ALPHABETIC SEQUENCE) Product Baryte Bentonite Cebodol-325

Packing bulk bulk bulk

GRANUAL BENTONITES for seismologic services (ALPHABETIC SEQUENCE) Product Bentonite QS 2 (Wyoming) Bentonite QS E2 (Europe) Bentonite QS 5 (Wyoming) Bentonite QS E5 Duranite Clay Balls

Packing 25kg bags 25kg bags 25kg bags 25kg bags 25kg bags

PACKED/PALLETIZED AND BULK (MUD-) CHEMICALS (PRODUCT-GROUPS PER APPLICATION)

Weighting Materials Item 002 048 010 011 050 E) Item 012 017 018 027 028 029 030 031

Product Baryte Baryte Cebodol-325 Cebodol-325 Cebodol-325

Packing 25kg bags bulk 25kg bags big bags bulk

LOST CIRCULATION MATERIALS Product Cellophane Grit Fine 2-4 mm. Grit Coarse 4-7 mm. Mica Fine Mica Course Mikhart 0.35-0.7 Mikhart 0.5-1.5 Mikhart 130

Packing 20kg bags 25kg bags 25kg bags 25kg bags 25kg bags 25kg bags 25kg bags 25kg bags

033 046

F) Item 005 006 009 015 019 021 022 023 024 025 026 035 036 037 045 G) Item 003 004 049 013 020 038 039 040 041 042 043 047 H) Item 001 007 008 014 016 032 034 044 I)

Mudfiber Walnuts

25kg bags 25kg bags

SALTS AND BASES Product Calcium Chloride Flakes Calcium Chloride Flakes Caustic Soda Pearls Edelwit Lime Gypsum Kalium Chloride Kalium Chloride Kalium Hydroxide Prills (KOH) Kalium Jodide Magnesium Chloride Magnesium Chloride Salt Broxo Salt NCP Salt NCP Sodium Bicarbonate

Packing 50kg bags big bags 25kg bags 25kg bags 40kg bags 25kg bags big bags 50kg drum 50kg drum 25kg bags big bags 25kg bags 25kg bags big bags 25kg bags

VISCOSIFIERS AND FLUID LOSS ADDITIVES Product Bentonam Bentonite Bentonite CMC ehv tvg 40 HEC Natrosol Stabilose LV Stabotemp HT Staflo Exlo Staflo R Starch (Flogcel) LV Starch (Flogcel) HV/TA XC-Polymer

Packing 50kg bags 50kg bags bulk 25kg bags 25kg bags 25kg bags 25kg bags

25kg bags 25kg bags 25kg bags

MISCELLANEOUS Product Aquamagic Carbogel-N Carbomul Coat B-1400 Fenoil AF-1103 (Defoamer) Milguard Pipelax Servodril CDM 791

Packing 25kg bags 25kg bags 55gal. drum 55gal. drum 50kg drum 25kg bags 55gal. drum 45kg drum

VERSA PRODUCTS

Item 01

Product Versamul NS

02

Versacoat HF

Packing

Function 208ltr. drum

Emulsifier

208ltr. drum

Emulsifier/Flfluid

loss agent 03

Versawet NS

208ltr. drum

04

LVO 69

05

Versa SWA

06

Esso EMI-4000

07

Calcium Chloride MI

50kgs sx m/t

s.g. agent

08

Lime MI

25kgs sx m/t

pH regulator

09

Kleen-up

208ltr. drum 205/215kgs

Alkal. Detergent

25kgs sx

Wetting agent Organophilic Clay

208ltr. drum m3

Superwetting agent Base oil

• Only chemicals with a valid Safe Handling Of Chemicals “SHOC" card shall be used • The SHOC cards contain important information on chemical products such as:

− − − − −

Composition of the chemicals. Usage instructions. Transport rules. Toxicity of the products. Safety/health instructions.

• Classes of products used in water-base drilling fluids are:

− − − − − − − − − − − −

Viscosifiers. Filtrate Reducers. Weighting Materials. Alkalinity Modifiers. Deflocculants. Shale control Additives. Lubricants. Stuck Pipe Release Agents. Defoamers. Inorganic Salts. Lost Circulation Materials. Corrosion Control Agents.

• Oil-base drilling fluids do not use such a wide range of chemicals as in water-base drilling

fluids, due to the inert non-polar nature of the oil external phase. Classes of products used in oil-base drilling fluids are: − Emulsifiers. − Viscosifiers (Suspending Agents). − Rheology Enhancers. − Oil Wetting Agents (Dispersants or Thinners). − Filtration Control Additives. − Inorganic Materials.

3.2.2.

Toxicity of drilling fluids

The short-term toxicity effects must now also include the long-term effects; including bioaccumulation and biodegradation. The toxic effects of the drilling fluid chemicals, discharged into the environment, depend on the characteristics of the chemical, the amount discharged and characteristics of the receiving environment.

4.10.1 3.2.3 Testing and evaluation of drilling fluid chemicals It is normal practise that after a technical evaluation by the Company, approval for field use shall be obtained from the authorities. It is the Companies requirement that the biodegradability of all drilling fluid chemicals can be demonstrated.

4.10.2 3.3

Waste Handling

4.10.3 3.3.1 Introduction The reduction of waste is necessary to minimise the environmental risks and to reduce costs. Environmental risk of a waste stream depends on the quantity and composition(s) of the waste stream and also on the way in which it is disposed. It is the policy of the Company to display "good housekeeping" practises in all venues at all times. Environmental risk by waste can be reduced by minimising the quantity of waste streams from the primary sources and ensuring that the stream can be disposed of and/or treated effectively. The waste handling disposal objectives are: • To increase recycling and re-use. • To incinerate. • To dispose of in an approved land fill site.

Legislation states that the Company remains responsible for its waste up until the recognized legal and recorded transfer to another party. Authorities require that all waste movements are reported and are traceable, and that all information/documentation is retained for an "infinite" (20 years) period.

4.10.4 3.3.2 Identification of waste streams In order to be able to minimise waste streams it is first necessary to identify what types of components are in the waste streams and in what quantity (percentage), their composition, and how to separate them.

4.10.5 3.3.3 Minimising of waste streams DRILLING CONTRACTOR contribute in two ways to minimizing the environmental impact and disposal costs of well engineering operations. Firstly by reducing the amount of waste produced and secondly by keeping the waste "pure" by reducing the number of components per shipment. The following guidelines should be considered: • Keep different types of mud and cuttings separated. Keep "pills" separate because of

their possible high oil concentration. • Minimise use of pipe dope to prevent the contamination of muds and cuttings. • Prevent the leakage and spills of chemicals. If leakage or a spill occurs treat it as a

separate waste. • Keep materials such as wood, bitumen, cement, etc. clean and separated to make

recycling possible. • Keep equipment in good (leak-free) condition and/or use drip pans underneath. • Keep location clean so that location water stays "clean". This water can be used for

cleaning equipment. • Use large bags whenever possible or reusable containers. • Use a mud supplier that can recondition fluids effectively and make an effort to reduce

volumes. • Minimize the making up of drilling fluid on location.

Contents

4. DRILLSTRING......................................................................................................................i 4.1 Introduction ...................................................................................................................i 4.2 Drillstring Design ...........................................................................................................i 4.2.1 Drill collars............................................................................................................i 4.2.2 Heviwate drillpipe ............................................................................................... iii 4.2.3 Drillpipe .............................................................................................................. iv 4.2.4 Accessories...................................................................................................... xiv 4.3 Bottomhole Assemblies............................................................................................. xiv 4.4 Drillstring and BHA Inspections................................................................................. xvi 4.4.1 General ............................................................................................................ xvi 4.4.2 Inspection requirements for drill collars, crossovers etc. ................................. xvi 4.4.3 Inspection procedure for drillstring parts ......................................................... xvii 4.4.4 API standards.................................................................................................. xvii 4.4.5 Inspection requirements for drillpipes ............................................................. xvii 4.4.6 Inspection procedures for drillpipes ................................................................ xvii 4.4.7 Inspection requirements for Heviwate drillpipes..............................................xviii 4.4.8 Inspection procedure for HW drillpipe .............................................................xviii 4.5 Corrosion..................................................................................................................xviii 4.5.1 Forms of corrosion ..........................................................................................xviii 4.5.2 Actions against corrosion ................................................................................. xix 4.6 Remarks for Slip Handling Techniques..................................................................... xix 4.6.1 Proper slip handling techniques ....................................................................... xix 4.6.2 Slips and bushing requirements....................................................................... xix 4.6.3 Tests for slips and bushings.............................................................................. xx Illustrations

Figure 4.1 Heviwate drillpipe................................................................................................... iv Figure 4.2 Drillpipe upsets ...................................................................................................... vi Figure 4.3 Drillpipe classification markings............................................................................. vi Tables

Table 4.1 Drill collars ................................................................................................................i Table 4.2 Heviwate drillpipe.................................................................................................... iv Table 4.3 Drillpipes ................................................................................................................. iv Table 4.4 Well depth and rotary speed for node and pendulum type vibrations..................... xi Table 4.5 Node vibration......................................................................................................... xi Table 4.6 Pendulum assemblies (rotary assy)...................................................................... xiv Table 4.7 Stiff (packed hole) assemblies (rotary assy) .......................................................... xv Table 4.8 Kick-off and sidetrack assemblies (bent sub) ........................................................ xv Table 4.9 Kick-off and tangent assemblies (NDS) ................................................................. xv Table 4.10 Built up assemblies (rotary) ................................................................................ xvi Table 4.11 Tangent assemblies (rotary assy)....................................................................... xvi

5. DRILLSTRING

5.1 Introduction Drillstrings used by drilling contractors consist of the following: •

Drill collars The drill collars provide the weight on the bit and the weight to keep the drillstring in tension whilst drilling.

•

Heviwate drillpipes The Heviwate drillpipes enable a smooth changeover from the stiff drill collars to the more flexible drillpipes.

•

Drillpipes The drillpipes create the connecting pipe line/drive line to the surface.

•

Accessories Accessories consist of all the extra tools required to assemble and to design a drillstring fit to do the specific job.

5.2 Drillstring Design 5.2.1 Drill collars For offshore drilling operations the drill collars given in Table 4.1 will be used.

Table 5.1 Drill collars OD (“) 9½ 8 6½ 43/4 31/8

Body style Spiral Grooved Spiral Grooved Spiral Grooved Spiral Grooved Flush

Connection 7 5/8 Reg 6 5/8 Reg 4 IF NC 35 2 7/8 PAC

•

The rotary shouldered pin connections shall all have an API stress-relief groove. The box thread connections shall be provided with a Drilco bore back stress relief groove.

•

The spiral grooving (Sine k profile) of the drill collar bodies is a great feature to reduce differential wall sticking.

•

For the recommended make up tongue for drill collar connections refer to API torque specifications. These values are the minimum requirements.

•

The threads of drill collars not in use must always be equipped with proper steel thread protectors to prevent damaging.

Length of drill collars The required collar length to achieve maximum desired bit weight can be calculated as follows: Ldc = Bitwm (cos of angle) (NP) (BF) (Wc) where: Ldc Bitwm BF Wc cos of angle NP

= = = = = =

required collar length, (m) to achieve the maximum bit weight maximum bit weight, (TONNE) buoyancy factor, dimensionless collar weight (in-air),(kg/m) hole angle from vertical (1 for vertical) neutral point design factor (0.85)

Operators usually run 10-15% more collars than Actual Bit Weight (ABW) would indicate. This gives a safety margin and keeps the buoyancy neutral point within the collars when unforeseen forces move the buckling point up into the weaker drillpipe section. Adequate collar weight should be available to run 2.0 - 2.5T per inch of bit diameter on bits larger than 61/4” and 1.5 - 1.6T per inch of bit diameter on bits smaller than 61/4”. Bottomhole assemblies must be designed to compensate for hole inclination. The most effective drill collar force that can be applied to the weight-on-bit is equal to the true buoyant force corrected by the cosine of the hole angle. Picking up drill collars

Cast steel thread protectors provide a means of dragging the collar into the "V" door and protecting the shoulders and threads. The pin protector must also be left in place to avoid damage to pin threads as the collar is pulled up the ramp into the V-door. A good grade of drill collar lubricant containing 60% finely powdered metallic lead or 40 to 60% finely powdered metallic zinc should be applied to the threads and shoulders. Lift subpins should be cleaned, inspected, and lubricated on each trip. If these pins have been damaged and go unnoticed, they will eventually damage all of the drill collar boxes. Make up of new drill collars The following should be considered when making up new drill collars: •

A new joint should be very carefully lubricated. Any metal to metal contact may cause a gall.

•

Make up hand tight using chain tongs.

•

Make up to proper torque with rig tongs.

•

Break out connection and inspect for minor damage, or lack of dope adhesion to threads.

•

Re-lubricate.

•

Make up to proper torque.

Torque control Use the make up torque recommended for the specific joint size, outside diameter, and bore of collars.

•

Torque is the measure of the amount of twist applied to two members as they are screwed together. The product of the tong arm length in metres and the line pull in newton’s is newton metres of torque.

•

With a 4ft tong arm and 5 000 lb.line pull at the end of the tong, TORQUE = 4ft x 5 000 lb = 20 000 ft/lbs

•

A line-pull measuring device (or torque measuring instrument) should be used in making up drill collars. It is important that line-pull be measured when the line is at right angle or 90 degrees to the tong handle.

•

When applying line-pull to the tongs, apply a slow, steady pull rather than jerking the line.

•

Drill collars larger than 7” diameter usually require a double-line pull. For example, a pulley at the tong handle is needed to obtain adequate line pull.

Refer to the Drilco Manual or equivalent for recommended makeup torque values for rotary shouldered drill collar connections (various connection styles) and for commonly used drill collar OD and ID sizes and styles. How to measure the required drill collar makeup torque:

The proper amount of makeup torque must be measured. There are two steps that must be worked out for all hook-ups: 1. Look in the torque Tables and find the amount of makeup torque recommended for the size drill collars and type of connections. 2. Divide this amount by the number of metres in the effective length of the tong arm. This will give the total line pull at the end of the arm.

Rig maintenance of drill collars •

It is good practice to break different joints on each trip, giving the crew an opportunity to look at each pin and box every two or three trips. Inspect the shoulders for galls, and possible "wash-outs".

•

Thread protectors should be used on both pin and box when laying the drill collars down.

Safety clamp (Dog Collar) The safety clamp is required for handling collars over the hole. It is necessary that the nut is made-up carefully. When not in use, the clamp should be kept in a safe place, free from damage and corrosion. 5.2.2 Heviwate drillpipe Heviwate is an intermediate weight drill stem member. It consists of heavy wall tubes attached to special extra length tool joints. It has drillpipe dimensions for ease of handling. One outstanding feature is the integral centre wear pad which protects the tube from abrasive wear. The wear pad acts as a stabiliser and is a factor in the overall stiffness and rigidity of one or more joints of Heviwate drillpipe.

Figure 5.1 Heviwate drillpipe Heviwate drillpipe, run in compression for bit weight, can reduce the hook load of the drill stem making it ideal for smaller rigs drilling deeper holes. In shallow drilling areas where regular drillpipe is run in compression, the more rigid Heviwate drillpipe will allow more bit weight to be run with less likelihood of fatigue damage. Heviwate drillpipe required for offshore drilling operations are given in Table 4.2.

Table 5.2 Heviwate drillpipe OD (“) 5 3½

Connection 4 ½” IF 3 ½” IF

Extra’s Smooth hardfacing on tool joints Smooth hardfacing on tool joints

Whilst drilling the Heviwate drillpipes are normally kept in tension but they are also used in compression to create weight on the bit. In cases of specific hole problems these might be a solution. In these situations drill collars can be omitted.

5.2.3 Drillpipe Drillpipes required for offshore drilling operations are given in Table 4.3.

Table 5.3 Drillpipes OD (“) 5 5

Weight (lbs/ft) 19,5 19,5

Connection 4 ½ IF 4 ½ IF

Grade G 105 S 135

Class Premium Premium

3½ 3½ 2 7/8

15,5 15,5 6,7

3 ½ IF 3 ½ IF 2 7/8 PAC

G 105 S 135 Special

Premium Premium Premium

•

Drillpipe must have internal-external upset flash welded tool joints.

•

All drillpipe must be plastic coated on the inside to protect it against corrosion.

•

To reduce tool joint OD Wear the 5” drillpipe must have smooth hard facing on the tool joints.

NOTE: Sufficient pup joints of the same quality must be available for 5” and 3½” drillpipe strings on board the rig.

Figure 5.2 Drillpipe upsets

Figure 5.3 Drillpipe classification markings

Collapse of drillpipe Typically, higher-strength pipe is required in the lower sections of the string for collapse resistance; Drillstem testing causes the most severe collapse loading on the drillpipe. The most severe collapse loading occurs when the evacuated (or partially empty) drillstring reaches the bottom of the well. The load from the annular mud tends to cause pipe collapse. Failure to fill the drillpipe when running into the well with a float valve in the drillstring, may also cause collapse. Completely plugged jets will prevent mud from entering the drillpipe when tripping into the hole. Drillpipe is usually designed with a factor of 1.3 since new pipe is seldom used when running a DST.

When the fluid levels inside and outside the pipe are equal, and provided the density of the drilling fluid is constant, the collapse pressure is zero at any depth: there is no differential pressure. If, however, there is no fluid inside the pipe the actual collapse pressure may be calculated by the following equation: Pc where:

Pc L Wg 101.973

=

(L) (Wg) 101.973

= = = =

net collapse pressure, kPa depth at which Pcacts, m drilling fluid density, kg/m3 constant

Use the API tables to calculate allowable collapse pressure. If the net pressure exceeds the allowable collapse pressure then the string is underdesigned and should not be used.

where:

Pac

=

Pp SF

Pac Pp SF

= = =

allowable collapse pressure, kPa theoretical collapse pressure from API tables (API RP7G) safety factor (1.1 - 1.3)

Tension in the drillpipe string Buoyancy is included in the tension evaluation because the string is designed based on maximum load. The tensile strength of drillpipe can be used to determine the correct working depth for a particular grade of pipe. Static tension loads require sufficient strength in the top joint of drillpipe to support the remaining submerged drillstring.

where:

P

=

P Ldp Lhdp Ldc Wdp

= submerged load hanging below this section of drillpipe daN = length of drillpipe, m = length of heavyweight drillpipe, m = length of drill collars, m = approximate weight per meter of drillpipe assembly in air, kg/m (includes tool joint weights) = weight per meter of heavyweight drillpipe, kg/m = weight per meter of drill collars, kg/m = buoyancy factor = a constant

Whdp Wdc BF 0.98065

((Ldp x Wdp)+(Lhdp x Whdp)+(Ldc x Wdc)) 0.098065 x BF

Tension load safety factor for drillpipe strings A design factor of 0.90 of the theoretical maximum tensile load is used to prevent permanent stretch of the drillpipe. Specific safety factors may be obtained from the manufacturer for a particular grade of pipe:

where

Pa

=

Pt x 0.9

Pa Pt 0.9

= = =

maximum allowable design tension load in daN theoretical tension load from API table, daN safety factor relating proportional limit to yield strength

A design safety factor may be calculated as the ratio of the maximum allowable design tension load to the calculated tension load: Safety Factor (SF) = Pa/Pt Drillpipe length requirements Depending upon the design criteria the length of drillpipe used for a particular grade of pipe can be calculated as: Ldp1

=

Pt x 0.90 - MOP - (Lhdp x Whdp) + (Ldc x Wdc) Wdp1 x BF Wdp1

For a second grade of drillpipe: Ldp2

=

Pt x 0.90 - MOP - (Ldp1 x Wdp1) + (Lhdp x Whdp) + (Ldc x Wdc) Wdp2 x BF Wdp2

For SI calculations divide the first portion of the equation (Pt x 0.9) by 0.98065 if Pt is expressed in daN. Overpull on drillpipe The term margin of overpull is used to represent the difference between the calculated load (P) and the maximum allowable design tension load (Pa). MOP = Pa - P This minimum overpull factor is applied to the tension load. The factor was originated to ensure the driller could safely pull a certain load on the pipe in the event of sticking.

Drillstring stretch Suspension of the drillstring in the hole results in a stretch or elongation of the pipe. Various effects such as string weight, buoyancy and temperature account for the increased length. The stretch of the drillstring can be calculated for each individual effect, with the overall stretch being the total of the previous values. Combined effects of string weight and buoyancy:

es where: es L MD

=

L2(7850-1.44 MD) 4.2239 x 1010

= = =

stretch, metres length of string, metres mud density, kg/m3

Effects of temperature: et

=

11.8 x 10-6 CL

where: et C L

= = =

stretch due to temperature, metres average temperature, degrees C length of drillstring, metres

eTot

=

es + et

where: etot es et

= = =

total stretch stretch due to string weight stretch due to temperature

Critical rotation speeds Critical rotating speeds in drillpipe strings which cause vibrations are often the cause of crooked drillpipe, excessive wear, rapid deterioration and fatigue failure. Critical rotational speeds will vary with length and size of drillstem and collars and hole size. There is evidence in recent field tests that excessive power is required at the rotary to maintain a constant speed at critical rotary speeds. This power indicator, plus surface evidence of vibration, should warn the crew that they are in the critical range. The worst condition of vibration occurs when two types of vibrations occur simultaneously resulting in serious damage to the drillstring. Table 4.4 shows the depths and rotary speeds at which the two types of vibration can occur.

Table 5.4 Well depth and rotary speed for node and pendulum type vibrations Drillpipe OD(inches) 23/8 27/8 31/2 4 41/2 5 51/2

Critical RPM 110 130 160 185 210 235 260

701 597 487 423 365 304 298

Vibration Coincidence Depths (m) 2865 2438 5486 2011 4511 1706 3870 1524 3413 1372 3048 5334 1219 2743 4846

The two types of vibration are:

1. The pipe between each tool joint may vibrate in nodes, as a violin string. Table 4.5 predicts critical rotary speeds to +/- 15%. Table 5.5 Node vibration Pipe size (inches) 23/8 27/8 31/2 4 41/2 5 51/2

Approx. critical rotary speed (RPM) 110 130 160 185 210 235 260

2. The second type of vibration is the vibration of the entire drillstring similar to the spring pendulum effect. This is less significant than the node type. RPM = 78 638.4 L Torsion on the drillpipe string Torsional strength is important when drilling deviated holes, deep holes, reaming, or when pipe is stuck. Torque applied to pipe while drilling may be approximated by the following equation: T

where: T P 9550 RPM

=

P x 9550 RPM

= = = =

torque delivered to drillpipe, Nm power to rotate pipe, kW a constant revolutions per minute

Breaking in new tool joints •

Newly machined surfaces are more apt to gall than those which have had some use. After some service, the surfaces undergo certain changes which offer more resistance to galling. Therefore, the initial makeup and first few trips are the most critical time and extra care is essential to give long, trouble-free service.

•

The new joint must be well lubricated. Apply generously on both pin and box.

•

Make up to proper torque then break-out connection and inspect for minor damage or lack of dope adhesion to threads. Relubricate and make up to proper torque.

•

On initial make up and the first few trips, make up new tool joints slowly and then tong them up tight. High-speed make up with spinning line or kelly spinner may result in galls. Avoid forced make up of improperly engaged threads. When stabbing a tool joint, the flat crest on new thread sometimes wedge against each other. A slight amount of reverse rotation should free them.

Picking up the drillstring Care should be taken in picking up or laying down drillpipe to protect threads and shoulders of boxes and pins. Thread compounds •

Pin and box threads and shoulders should be thoroughly cleaned and dried so that the thread compound will properly adhere to the surface. Tool joints and other rotary shouldered connections are subjected to high unit stress which may cause galling or seizing without the benefit of a separating film. Thread compounds provide this film and help minimise excessive make up. Thread compounds containing 40 to 60% by weight of finely powdered metallic zinc are recommended.

•

Thread compounds should not be thinned for ease of application. Dilution will reduce the amount of available metal filler.

•

Thread lubricants made according to API Bulletin 5A2 are not to be used on tool joints. They are the API recommended lubricant for tubing and casing, and are made to have a low co-efficient of friction allowing make up with low torque.

Going in the hole •

Lubrication Before each joint is added to the string, it should be cleaned and dried. This includes complete removal of rust preventatives or previously applied tool joint compound. When the joint is picked up and on each trip, the box threads and shoulders should be doped, distributing the compound over threads and shoulders.

•

Stabbing Do not allow the ends of the pin to strike the box shoulders. Such damage may be avoided by achieving co-ordination between the drillers and floor men.

•

Spinning up Before spinning up pipe, be sure connections are in alignment. High-speed rotation can burn threads. Kelly spinners rotate the kelly at high rates into the mouse hole joint, and then the mouse hole joint going into the joint in the rotary table. The connection must be clean, adequately lubricated and the joint does not wobble and bind. After both spinning operations, the rotary tongs should be used to tighten the joints to the recommended torque.

•

Make up Avoid forced make up of improperly engage threads. When stabbing, flat thread crest on the pin can land opposite similar crests on the box, this results in jamming action and forced make up which will cause serious damage. A slight amount of left-hand rotation with tongs will free them. The stand can be lifted, rotated slightly and stabbed again.

•

Tonging − Tonging tool joints is the most important single factor in preventing tool joint damage. Refer to API 7G for recommended make up torque values for the various sizes, types and classes of tool joints. − The minimum makeup torque is 10% less than the recommended values. Below this torque, joints may not develop sufficient strengths. − When making up or breaking out drillpipe stands, back-up tongs must be used to prevent pipe slippage and damage. − Keep the tool joint as close to the rotary table as possible during makeup and break out. There is a maximum height that a tool joint may be positioned above the rotary slips and still resist bending. Line pull should not exceed recommended makeup torque with tongs at 90 degrees to the jerk line.

•

Kelly-saver sub − The kelly-saver sub should be cleaned and inspected every time it is removed from the rat hole and always maintained in good condition as it mates with every tool joint box in the string. − Keep a spare kelly-saver sub in good condition on the rig at all times. − The length of kelly-saver subs can become critical if the box connection is re-cut several times.

Coming out of the hole •

Breaking out Use both tongs to break out joint. Rotate out slowly. Keep just enough tension on the hook spring to keep minimum pressure on the disengaging threads; but keep enough tension to avoid the end of the pipe striking the shoulder. When the spring hook lifts the pin from box, the joint must be pushed to the side to prevent the pin from striking the shoulder when it drops back down.

•

Lowering the elevators Box shoulder may be badly damaged if struck by elevator or hook. Damage this severe can be properly repaired only by reworking the box in the machine shop.

•

Alternating breaks Come out of the hole on a different break each trip so that every connection can be periodically broken and its condition observed and torque rechecked. Excessive breakout torque may indicate abnormal downhole torque conditions. A check should be made for damage due to excessive torque.

•

Standing back When standing the pipe back, be sure set back area is clean. If the desired position of the stand is not achieved, do not use wrench jaw or other sharp-edged tool to jack into position.

Laying down the drillstring

WARNING: When laying down the drillstring, install thread protectors before swinging through the "V" door and onto the walk. Keep the walk clear - do not allow the joint coming down to hit

another joint or other objects on the walk. Be sure thread protectors are installed tightly on boxes and pins. 5.2.4 Accessories Drillstring accessories consist of: •

Crossovers Sufficient crossovers will be available on the rig to assemble normal drilling bottomhole assemblies. These crossovers shall be of the same quality as the drill collars. All threads must have stress relief grooves.

•

Stabilisers and Reamers Stabilisers and reamers are not an internal part of the rig package. These items will be rented from specialised contractors. The requirements for thread design and quality are identical to the requirements for the rig owned components.

•

Jars Drilling/Fishing jars are also rented from specialised companies. Weir Houston jars have a good performance record in North Sea drilling.

•

Mudmotors Mudmotors are supplied as a rental item by highly specialised companies. Mudmotors will be used for performance drilling and for directional drilling purposes.

•

Fishing tools Some basic fishing tools are available on the rig such as overshots, used for all drillpipes, tool joint sizes, and drill collars. This way the first fishing attempt can be done by the rig itself when necessary. More complex fishing will be advised by specialised fishing companies (Tristate, Red Baron etc.). The fishing companies will supply a fitting fishing kit for all relevant circumstances.

5.3 Bottomhole Assemblies With a proper Bottomhole Assembly the hole can be made with the requested drift angle and direction. All wells, even a vertical one, are directional drilled. Normal vertical hole drilling is usually done by the rig crew on its own. Directional drilling requires a specialised qualified directional driller on the well site. The directional drilling contractor will make the well plan/plot and will advise the tools to be supplied. Tables 4.6 through 4.11 show some examples of Bottomhole-Assemblies.

Straight hole section:

Table 5.6 Pendulum assemblies (rotary assy) 24” Bit 90’ DC’s 24” Stab 60” DC’s 24” Stab DC’s HW

17-1/2” Bit 90’ DC 17-1/2” Stab 60’ DC’s 17-1/2” Stab DC’s HW

16” Bit 90’ DC 16” Stab 60’ DC’s 16” Stab DC’s HW

12-1/4” Bit 60-90’ DC’s 12-1/4” Stab 30-60’ DC’s 12-1/4” Stab DC’s HW

8-1/2” Bit 60’ DC’s 8-1/2” Stab 30’ DC’s 8-1/2” Stab DC’s HW

5-7/8” Bit 30’ DC’s 5-7/8” Stab 15’ DC 5-7/8” Stab DC’s HW

Table 5.7 Stiff (packed hole) assemblies (rotary assy) 24” Bit NB Stab S.DC 24” Stab 30’ DC 24” Stab 30’ DC 24” Stab DC’s (Jars) HW

17-1/2” Bit NB Stab S.DC 17-1/2” Stab 30’ DC 17-1/2” Stab 30’ DC 17-1/2” Stab DC’s (Jars) HW

16” Bit NB Stab S.DC 16” Stab 30’ DC 16” Stab 30’ DC 16” Stab DC’s (Jars) HW




Kick-off and build section:

Table 5.8 Kick-off and sidetrack assemblies (bent sub) 24” 17-1/2” 16” 12-1/4” Bit Bit Bit Bit 11-1/4” DHM 9-1/2” DHM 9-1/2” DHM 8” DHM 2 Bent Sub 2 Bent Sub 2 Bent Sub 2 Bent Sub 60’ NMDC 60’ NMDC 60’ NMDC 60’ NMDC DC’s DC’s DC’s DC’s (Jars) (Jars) (Jars) (Jars) HW HW HW HW The assemblies in Table 4.8 can be used for hole corrections.

8-1/2” Bit 6-3/4” DHM 1-1/2 Bent Sub 60’ NMDC DC’s (Jars) HW

5-7/8” Bit 4-3/4” DHM 1 Bent Sub 60’ NMDC DC’s (Jars) HW

Table 5.9 Kick-off and tangent assemblies (NDS) 17-1/2” 16” 12-1/4” 8-1/2” 5-7/8” Bit Bit Bit Bit Bit 11-1/4” NDS 11-1/4” NDS 9-1/2” NDS 6-3/4” NDS 4-3/4” NDS 16-3/4” Stab 15-1/2” Stab 11-3/4” Stab 8” Stab 5-1/2” Stab 1 1 1 1 (+ /2”) (+ /2”) (+ /2”) (+1/4”) (+ /4”) 60’ NMDC 60’ NMDC 60’ NMDC 60’ NMDC 60’ NMDC 60’ NMDC (22” Stab) (16-1/2” Stab) (15-1/4” Stab) 11-1/2” Stab 7-3/4” Stab 5-1/4” Stab 1 1 1 1 (+1”) (+ /2”) (+ /2”) (+ /2”) (+ /4”) (+1/4”) DC’s DC’s DC’s DC’s DC’s DC’s (Jars) (Jars) (Jars) (Jars) (Jars) (Jars) HW HW HW HW HW HW The assemblies in Table 4.9 can be used for hole corrections. To change them into dropping assy change the string stab to one size larger. 24” Bit 11-1/4” NDS 23” Stab (+1”)

Table 5.10 Built up assemblies (rotary) 24” Bit NB Stab S.DC U.G. Stab 90’ DC 24” Stab 60’ DC’s 24” Stab DC’s (Jars) HW

17-1/2” Bit NB Stab S.DC U.G. Stab 90’ DC 17-1/2” Stab 60’ DC 17-1/2” Stab DC’s (Jars) HW

16” Bit NB Stab S.DC U.G. Stab 90’ DC 16” Stab` 60’ DC 16” Stab DC’s (Jars) HW



5-7/8” Bit NB Stab S.DC U.G. Stab 30-45’ DC 5-7/8” Stab 15-30’ DC 5-7/8” Stab DC’s (Jars) HW

Table 5.11 Tangent assemblies (rotary assy) 24” 17-1/2” 16” 12-1/4” 8-1/2” 5-7/8” Bit Bit Bit Bit Bit Bit NB Stab NB Stab NB Stab NB Stab NB Stab NB Stab S.DC S.DC S.DC S.DC S.DC S.DC U.G. Stab U.G. Stab (17U.G. Stab U.G. Stab (12U.G. Stab (8- U.G. Stab (51 1 1 7 (24”) /2”) (16”) /4”) /2”) /8”) 30’ DC 30’ DC 30’ DC 30’ DC 30’ DC 30’ DC U.G. Stab U.G. Stab U.G. Stab U.G. Stab U.G. Stab U.G. Stab 30’ DC 30’ DC 30’ DC 30’ DC 30’ DC 30’ DC 1 1 1 24” Stab 17- /2” Stab 16” Stab 12- /4” Stab 8- /2” Stab 5-7/8” Stab DC’s DC’s DC’s DC’s DC’s DC’s (Jars) (Jars) (Jars) (Jars) (Jars) (Jars) HW HW HW HW HW HW To change the assemblies in Table 4.11 into dropping assy change U.G. Stab to full gage.

5.4 Drillstring and BHA Inspections 5.4.1 General The inspection of drillpipe and collars is intended to reduce the cost of unnecessary failures and their resulting fishing costs. The frequency of the inspections must be based on economics and practicality. If drilling is being performed in a region where failures are very rare due to non-severe loading conditions, and the cost of a failure is not excessive, then no inspections are required (i.e. shallow gas). High-cost regions such as the North Sea require higher inspection frequencies.

NOTE: All defects which are discovered during the inspection process must be investigated. This process generally involves grinding cracks. Any size of a crack is a reject, so normally the suspect area is grind probed only enough to prove that the indication is in fact a crack; a couple of thousandth’s of an inch is normally quite sufficient. Defects should not be ground any deeper than the classification (i.e., Premium) allows as a minimum standard. If the defect is ground deep enough to determine that the joint will fail the inspection criteria, then it should be rejected and set aside for further shop investigation. 5.4.2 Inspection requirements for drill collars, crossovers etc. Before the drilling for a new contract starts all drill collars, crossovers etc., must be inspected.

Under normal circumstances an inspection interval of 300 rotary hours has proved to be successful for BHA components in operations. Abnormal use of the BHA components requires tailor made inspection programs.

5.4.3 Inspection procedure for drillstring parts Inspecting drillstring parts, e.g., drill collars, crossovers, etc., comprises: •

Visual check of shoulders and threads.

•

Check thread profile with thread gauge.

•

Check for cracks in pin-and-box threads and relief grooves using the MPI method.

•

Check the OD’s for wear.

5.4.4 API standards The main goal of field inspection for drillpipe and bottomhole assemblies is to ensure that the tubulars will meet their API dimensional and performance ratings. The primary reference documents are the following: API RP 7G:

Recommended Practice for Drill Stem Design and Operating Limits.

API RP 5A5: Recommended Practice for Field Inspection of New Casing, Tubing and Plain-End Drillpipe. API RP 5D:

Specification for Drillpipe.

API Spec 7:

Specification for Rotary Drilling Equipment.

5.4.5 Inspection requirements for drillpipes Before start of a new contract all drillpipes must be inspected. Under normal circumstances a one year or 30 000 m drilling inspection interval has proven to be successful in North Sea operations. Abnormal use and occurrences require tailor made inspection programs.

5.4.6 Inspection procedures for drillpipes •

Tool joints 1. Visual check thread profile and shoulder. 2. Check thread profile with thread gauge (API-7). 3. Check OD for wear (API-7).

•

End area

1. Ends are electromagnetically inspected according to API-RP 5 A5. •

Pipe body 1. Electromagnetic Inspection of the whole tube (API-RP7G). 2. Check pipe body OD over full length. 3. Check slip area on slipmarks.

5.4.7 Inspection requirements for Heviwate drillpipes Before beginning a new contract all Heviwate drillpipes must be inspected. Under normal circumstances a 300 rotary hour inspection interval has proven to be successful in drilling operations.

5.4.8 Inspection procedure for HW drillpipe •

Tool joints 1. Visual check of shoulders and thread profile. 2. Check thread profile with thread gauge. 3. Measure tool joint OD. 4. Magnetic- Particle- Inspection for threads and relief grooves.

•

Pipe body 1. Magnetic particle inspection for end areas.

5.5 Corrosion 5.5.1 Forms of corrosion Knowledge of the forms of corrosion helps determine the cause and corrective action: •

Uniform attack All the corrosive agents cause uniform or general corrosion, but with different degrees of intensity. Strong acids and salts are usually the most severe; carbon dioxide and hydrogen sulphide are relatively mild. Metal loss from uniform corrosion results in failure from loss of strength.

•

Localised attack Corrosion may be localised in small, well-defined areas, causing pits. Pitting is difficult to detect and evaluate, since it may occur under corrosion products, mill scale and other deposits, in crevices or highly stressed areas. Pits can cause washouts that serve as points of origin for fatigue cracks.

•

Erosion-Corrosion Erosion of protective oxide films or layers of corrosion products and corrosion leads to pitting and early failure.

•

Electro-chemical reaction In the presence of an electrolyte (drilling fluid) to conduct current, a reaction similar to

that in a battery can be established. Very minute differences in steel composition can create this situation. Pits are formed which may result in stress concentration and fatigue cracking. •

Corrosion Fatigue The cumulative effect of corrosion and cyclic stress is greater than the total damage from each.

5.5.2 Actions against corrosion •

All drillpipe must be internally coated with plastic to protect the pipe body against corrosion.

•

Whilst laying down a drillstring, each joint must be flushed with fresh water to remove harmful chemicals.

•

All tool joint threads must be cleaned and properly doped.

•

All drillpipe bodies must be cleaned and preserved with a proper inhibitor before storing for a longer period of time.

5.6 Remarks for Slip Handling Techniques 5.6.1 Proper slip handling techniques 1. The downward motion of the drillpipe must be stopped with the brakes, not the slips. 2. Do not let the slips ride the pipe. This not only damages the slips by reducing the configuration of the gripping elements, but in the event a tight spot is encountered while coming out of the hole, the slips will automatically be set and greatly complicate freeing of the pipe. 3. Do not use slips designed for one specific size of pipe on any other size of pipe. 4. Under no circumstance is the use of re-sharpened gripping elements permitted. 5. Immediately repair all damages to rotary slips. 6. If pipe will not hold in the rotary slips due to worn gripping elements, the gripping elements must be replaced immediately. Slippage of pipe through the slips due to worn inserts can result in dropping the pipe. 7. When running in the hole, be sure that slips do not accidentally catch the drillpipe tool joint.

5.6.2 Slips and bushing requirements Successful handling of drillpipe with rotary slips and master bushings for all depths and drilling conditions is directly dependent on the following factors: •

Rotary table master bushing and/or slip bowls and slips must have the correct and matching API specifications.

•

Square drive master bushings and/or matching bowls and shorter slips can be used successfully when hook loads do not exceed 111 000 daN. For greater hook loads it is

advisable to use four-pin drive bushings with extended slip bowls. This must be in combination with extra long rotary slips having a full tapered back to match. •

Damage, particularly crushing, of the drillpipe may occur through the use of a damaged or worn rotary table, master bushing and/or slip bowl or slips. This is particularly true when using a new and old combination of any of these elements.

5.6.3 Tests for slips and bushings To determine whether the rotary slips and master bushing conform to correct specifications, a simple field test procedure is recommended. This test is based on the effective gripping action of the rotary slips:

1. Pick up the kelly and set the slips below the usual slip area on the drillpipe. 2. Pick up, remove the slips and carefully examine the gripping area to determine the length, circumferential amount, and uniformity of holding, by the gripping elements. 3. If the rotary master bushings and slips are in good condition, a uniform gripping pattern can readily be observed, matching the length of the slip being employed. Under such conditions, the total transverse load would be equally distributed over the maximum slip area and crushing will not occur. 4. If the gripping pattern is such that it does not conform to the entire slip; either the slips, or the master bushing, or both are out of specification. To determine which is at fault, the same tests should be repeated with a new or like new set of rotary slips. If this corrects the problem and the pattern is uniform, it is the rotary slips which were at fault. On the other hand, if in using the new or like new rotary slips, the uniform pattern is still not observed, it is evident that the master bushing is out of specification. It is necessary that the slips and/or the master bushing be properly repaired or replaced immediately. 5. Do not use field gauges to determine master bushing and slip wear as they cannot be used under load conditions, and therefore do not measure actual displacements caused by wear.

Contents

5. OPERATIONS ......................................................................................................................i 5.1 Introduction ...................................................................................................................i 5.2 Drilling ...........................................................................................................................i 5.2.1 Bit selection......................................................................................................... ii 5.2.2 Bit pulling guide.................................................................................................. vi 5.2.3 Concurrent Operations...................................................................................... vii 5.3 Drill Off Tests ............................................................................................................. vii

5.4 Plugging and Abandonment...................................................................................... viii 5.5 Emergency Procedures............................................................................................. viii Forms

Form 5.1 Bit pulling guide worksheet...................................................................................... ix THIS PAGE IS INTENTIONALLY LEFT BLANK

6. OPERATIONS

6.1 Introduction This section contains information on factors that need to be taken into account during the safe operation of wells during the drilling phase in offshore operations.

6.2 Drilling The following is an outline of several general drilling practices which are based on Company and other operators’ experiences with drilling. These practices may not have an application to a particular situation. However, they should be seen as general guidelines to assist in improving the overall drilling performance. Company preferred drilling practices are as follows: •

The drillpipe should be strapped after major changes in the drilling string have taken place before logging, coring, testing and setting casing.

•

Company Drilling and Exploration personnel are to be advised immediately of any drilling break, lost circulation, well kick, or other abnormal drilling conditions.

•

All drilling breaks should be treated as coal and operations must proceed with caution. Drill no more than half of one metre, pick up drillstring, and circulate bottom-up and/or check for flow.

•

When sour gas is produced in any drillstem test, the flow period should be terminated when the sour gas reaches surface.

•

Do not spud bit to break up cement plug while drilling out.

•

Either the driller or a nominated crew member should be at the brake at all times.

•

Adequate collar weight should be available to run 2.0 to 2.5T per inch of bit diameter on bits larger than 61/4 inch and 1.5 to 1.6T per inch of bit diameter on bits smaller than 61/4 inch. The amount of drill collar weight available must take the buoyancy effect of the mud into account. The buoyancy factor can be determined from tables or by weighing the drill collar string after it is completely immersed in well fluid.

•

The neutral point in the drillstring should be maintained in the drill collar or heavy weight drillpipe when drilling.

•

Where the drilling rate is slow, at deeper depths, or in troublesome areas, the pipe should be worked up at least ten metres once every three or four hours. When drilling with diamond bits or with long-life button bits, make a short trip at least once every twenty-four hours. It is possible that more frequent short trips will be required.

•

A close check on mud properties and pit levels should be maintained. Insuring that all instrumentation such as the pit volume totalizers, flo-sho, H2S monitors, etc., are properly calibrated and in good working order.

•

When making connections, the pumps are not shut off until within three metres of slip setting point. If possible, the pipe should be kept moving and rotating at all times.

•

In deeper holes, small hole or holes where high mud rates are used, the pipe should be pulled and run slowly to avoid excessive surge and swab pressures. Rotate and/or move the pipe upward when breaking circulation after trips and connections.

•

A mud saver or a stripper rubber should be used on all trips out of the hole. When out of the hole, a rotary hole cover should be installed or the stripper rubber closed; if one has been installed.

•

For Company contracted rigs, the limit on hook load is stated in the contract or by letter agreement. Permission from both the Company and the drilling contractor must be obtained before exceeding these limits.

•

In the event that gauge trouble is encountered with bits, it may be desirable to make a special run with a reamer type bit rather than a drilling bit or a regular drilling bit with a reamer immediately above the bit. If a reamer is run immediately above the bit, caution should be exercised from a deviation standpoint, since this type of hook-up would tend to increase the angle. Therefore, in most instances no hole should be made with this type of a hook-up.

•

When using packed hole assemblies in areas where excessive hole deviation tendencies exist, continuous checks should be made on the outside diameters of reamers, stabilisers, etc. A little wear on these tools could create a deviation problem.

•

If drilling is rough, a shock sub should be considered. Placement of the shock sub above the bit or above the bit and the reamer could cause excessive deviation. Thus a shock sub could be run about two drill collars above the bit.

•

If bit plugging is a problem the use of a float should be considered.

•

A drillstring should have a minimum of one-third of its ultimate strength reserved for pulling.

When it is necessary to put heavy loads on a derrick or mast, it must be remembered that hook load and derrick or mast loads are not the same. Derrick or mast loads can be approximated as follows: Hook Load No. of Lines to Block

x (No. of Lines to Block + 2) = Approximate Derrick or Mast Load

This does not take into consideration friction factors or the position of either the dead or fast line. A good general rule to follow is to not load the derrick or mast more than fifty percent of the Gross Nominal Capacity.

6.2.1 Bit selection Bit types are constantly changing and it is difficult to compare bits from different manufacturers. However, bit programs should be prepared by using offset well data and operational experience within an area. They are a guide to assist the Company Representative in making a choice of bit to run. Any deviation from the International Association of Drilling Contractors (IADC) code must be approved by the Company Representative. Bit types are selected and specified by the current IADC coded bit classification. The IADC code consists of three numbers classifying different features as follows: •

The first digit designates the series of roller cone bit: Number 1 to 3 indicate milled tooth bits and 4 to 8 indicate insert bits. The higher the number within each series indicates the harder formations a bit can drill.

•

The second digit indicates the sub-classification of formation hardness. Numbers range from 1 to 4 for each series, designating from softest to hardest.

•

The third digit indicates the following features:

1. Standard. 2. Air Bit. 3. Gauge Protection. 4. Sealed Bearing. 5. Sealed Bearing and Gauge. 6. Friction Seal Bearing. 7. Friction Seal Bearing and Gauge. 8. Directional. 9. Special Features, i.e., bits with a centre nozzle. For example an IADC designation of 5-1-7 would be an insert bit designed to drill soft formations (5). In this case, the bit is best suited to drill the softer formations in the soft range (1), and the bit has a journal bearing and gauge inserts (7). The following codes are to be used to identify the original manufacturer of a specific bit type: •

American Coldset

AC

•

Christensen

CR

•

Diamant Boart

DB

•

Experimental

EX

•

Hughes (Western Rock Bit)

HU

•

KanDrill

•

Reed

RD

•

Security

SE

•

Smith

SM

KD

NOTE: DO NOT use supply company names or abbreviations in place of the manufacturer’s code. Bits run from manufacturers other than those listed above must have prior approval by both the Operations and Engineering Groups to ensure adequate performance documentation is completed. If performance proves economically viable, then the manufacturer's name will be added to the above listing. The following procedure is to be followed to provide consistency in reported information on bit records. •

Surface Hole: 1. Surface hole bits are to be designated with a sequential number commencing with one (1) and followed by the letter "A". 2. A pilot bit number should be followed by the letter "B". 3. The bit used after the pilot bit to ream or open the hole is recorded on two lines to specify reaming time and meterage, as well as drilling time and meterage. The reaming time on the "A" bit is shown, but not included in the cumulative hours.

•

Intermediate or Main Hole:

1. The rotating time on the intermediate or main hole section should begin at zero. 2. Bits are numbered sequentially starting at one (1). 3. The numeric order is continued from intermediate to main hole. Do not start at one (1) again. •

Rerun Bits: 1. Bits that are rerun should be prefixed with the abbreviation "RR". In the same hole the bit retains its original sequential number. Meterage must be drilled by another bit prior to calling a bit a rerun. For example, a bit run before a drillstem test (DST) is not a rerun when drilling proceeds after the DST. 2. The numbering sequence if bit number 2 was rerun after bit number 3, is as follows: 2, 3, RR2, not 2, 3, RR4. 3. Bits that are rerun form another well should be numbered sequentially from the last bit run in the current well and the number prefixed by "*RR". The asterisk would refer to a footnote containing the previous history of the bit, including meterage, hours and condition.

•

Coring: 1. Core bits are to be numbered sequentially starting at "1C". 2. "RR1C" would indicate a rerun with bit "1C". The next bit (if a different one) would be "2C". 3. If "RR1C" is used for another core, the number would remain "RR1C". 4. Core bit metres and hours are recorded on the appropriate line in the bit record but are put in brackets and are not included in the cumulative totals. 5. The reaming time on the drill bit following the core is added to the cumulative total. 6. The drill bit run after the core should be recorded on two lines to specify reaming time and meterage on one line and drilling time and meterage on another.

•

Bit Grading: The condition of a bit when it comes out of the hole is an extremely important parameter in: − Selecting the next bit to go in the hole. − Selecting bits to drill the same interval in future wells.

Bit grading was standardized in 1963 on milled tooth bits, and in 1971 on insert bits. A summary of the IADC standard follows and is to be applied to all bits run by Coparex. Bits are graded on "TBG" Tooth, Bearing, Gauge. The grading indicates the life of the bit used. − Tooth dullness for milled tooth bits is reported in eighth’s (1/8) of the original tooth height, and is prefixed by a T. (e.g., a grading of T3 means that the tooth height is worn by 3/8 of its original height). − Tooth dullness for insert bits is reported in eighth’s (1/8) of the total number of inserts lost or broken (i.e., a grading of T5 would mean that 5/8 of the total number of inserts were lost or broken). As a guide for the potential rerunning of an insert tooth bit, the

penetration rate is approximately cut in half for every 1/8 of the total amount of inserts lost or broken. Thus, if a large amount of meterage (greater than 200 m) is to be drilled with any bit rated lower than a T1, a new bit should be run. Refer to the following:

Tooth dullness T1 T2 T3 T4 T5 T6 T7 T8

•

Milled tooth (tooth height gone) 1 /8 1 /4 3 /8 1 /2 5 /8 3 /4 7 /8 all

Insert bits (inserts lost or broken) 1 /8 1 /4 3 /8 1 /2 5 /8 3 /4 7 /8 All lost or broken

Bearing condition. Bearing life used is reported in eights (1/8) as shown in the following: Bearing Condition Bit Grade B1 B2 B3 B4 B5 B6 B7 B8

Bearing Life Used 1 /8 1 /4 (tight) 3 /8 1 /2 (medium) 5 /8 3 /4 (loose) 7 /8 (locked or lost)

•

Bit Gauge: When drill bits are under gauge, they should be recorded by the number of millimetres (mm) which the bit is under the original bit diameter. Zero (0) indicates that the bit is still in gauge.

•

Drag Bit Evaluation: Drag bits include diamond, PDC, fishtail and any other bit which has no bearings and which relies principally on shearing and ploughing action to remove rock from the bottom of the hole.

•

Grading of drag bits must be performed by the Company Representative and shall be reported on the tour sheet, the bit record and the service order for the bit.

•

The decision process in grading a drag bit should generally proceed as follows: Is the bit reusable?

Yes With repair? Grade 4 - 7 Based on amount of repair required

No No repair? Grade 1 - 3 Based on wear only

Grade 8 Salvage value

These gradings are commonly expressed as a percentage of the bit life consumed or in a monetary value of bit life consumed (bit damage). This rating will only be an estimate for diamond bits with apparently no damage, as true wear can only be measured under a microscope in a laboratory. The remainder of the bit record is to be filled out in detail using average data of any given bit run for WOB, RPM, and pump data. All bits must be accounted for at the end of the well. Ensure proper material transfers are completed for ALL bits.

6.2.2 Bit pulling guide Optimizing bit runs on a cost/metre basis can be useful in reducing drilling costs. This analysis is mainly applied to deeper hole sections, i.e., the 2nd, 3rd, etc., and bit below the shoe. When used in conjunction with other indicating factors such as table torque, it can also help to avoid problems like balled bits and lost cones. This analysis is based on the fact that the drilling cost/metre will decrease to a minimum point sometime during the bit run and then begin to increase again. The bit should be pulled after reaching the minimum point. Of course, pulling a bit is subject to field conditions such as leaving a bit in longer in order to drill a few more metres to core point or total depth. This method is primarily applicable to milled tooth bits, or to soft insert bits drilling into progressively harder formations. In both of these situations as the rate of penetration (ROP) gradually decreases, the cost/metre will fall to a minimum and begin to rise again. In some cases, such as harder insert bits drilling through homogeneous formations, the ROP may not decrease significantly. In this instance, bit bearing life (i.e., rotating hours) should determine when to pull the bit. By plotting the cost/metre against the penetration of the bit, formation changes can often be seen as a definite change in the slope of the line. If such a change occurs where the formation is known to remain constant, then the bit may be wearing out and may have to be pulled.

The cost/metre analysis is based on the equation: C

Where: C B R TR TT P

=

(B + RP(TR + TT)) P

= = = = = =

Drilling Cost per metre Bit Cost Rig Operating Costs $/hr Rotating (drilling) time on bit hr Round trip time Penetration of bit during TR m

$/m $

hr

The round trip time is a function of rig size and capacity, hole conditions and formation stability as well as depth. An average rate for medium depth wells (1 500m) is 500m/hr. Refer to the Bit Pulling Guide Worksheet page 5.10.

6.2.3 Concurrent Operations Concurrent Operations are operations which require simultaneous drilling, production or engineering activities to be carried out simultaneously at one location. To ensure safety, when a jack-up is drilling on a producing platform, certain rig modifications are required for protection of the platform equipment from accidentally dropped equipment/pipe, and specialised communication and emergency procedures. The link up of the telephone, fire alarm, and ESD system, will be detailed for each specific rig/platform accordingly, as each may be slightly different. This will be detailed in the Concurrent Operations Script.

6.3 Drill Off Tests The following procedure will achieve optimum bit performance: •

Optimum Bit Weight 1. Set the rotary at the constant rpm expected to provide maximum penetration rate. 2. Increase bit weight 4 to 6T above what is expected for the maximum penetration rate (DO NOT EXCEED MAXIMUM WEIGHT ON BIT OR AVAILABLE DRILL COLLAR WEIGHT). 3. Drill off 1 or 2T (use the same value for each step). 4. Record the increment start and end point and the number of seconds that it took to drill the increment. 5. Repeat steps (a) 3 and (a) 4 until the force on the bit is 4 to 6T less than what is expected to be the optimum weight on the bit. 6. The weight increment drilled off in the least amount of time is the weight to be used as the starting point to find optimum rotary speed.

•

Optimum Rotary Speed 1. Raise the rpm up to the bit maximum or rig maximum, whichever is less. 2. Drill off 1 to 2T (using the same value for each step). 3. Record rpm and time taken to drill off the weight increment. 4. Reduce rpm by 10 (or another convenient number depending on how many increments are expected to highlight the optimum). 5. Adjust force on bit back to the starting point weight. 6. Repeat steps (b) 2 through 6 until it is felt that rotation is 30 to 50 rpm less than optimum.

•

Optimum Wob and RPM 1. The weight from step (a) 6 and the rpm that drilled off the 1 to 2T is the least amount of time from step (b) 6 from a near optimum drilling condition.

2. Repeat the complete sequence using weight and rpm combinations and smaller step sizes close to the conditions as outlined in step (c) 1. 3. Drill-off testing should be done every 2 to 3 hours when new formations are penetrated, and when changes are made to the mud or hydraulics. •

Alternate Method When penetration rates exceed approximately 10 m/hr. (i.e., it becomes difficult to time 1 to 2T drill-off weights), a variation of the above method is to mark the kelly in 0.3 m increments and record the time taken to drill 0.3 m in the least amount of time.

6.4 Plugging and Abandonment Under normal drilling operations it is expected that plugging and abandonment procedures will not be necessary. However, see Section 11 and 18 of this manual in the event that the wells require plugging or abandonment.

6.5 Emergency Procedures Emergency procedures must be specific to the environment in which the operations are taking place, i.e., offshore geographical location and the availability of third party assistance and medical facilities. When the Emergency Response Plan is prepared, the following should be considered: Ensure compliance with local/international regulations/legislation •

Include government interfaces.

•

Emergency planning zone.

•

Evacuation plans.

•

Medical aid.

•

Environmental considerations.

•

Shutdown procedures for ignition sources.

•

Disconnecting procedures for MODU's.

•

Closing procedures for watertight doors and hatches.

•

Survey accuracy.

•

Relief well drilling.

•

BOP equipment stockpile (fire fighting/mud mixing/pumping equipment, kill manifold, capping equipment).

•

Subsurface safety valves and emergency shutdown systems.

Contingency plans shall be prepared and regular emergency response exercises shall be carried out to ensure that the required emergency actions are familiar to all parties that may be involved, and to test logistics and equipment.

Form 6.1 Bit pulling guide worksheet

Contents

6. DRILLING FLUIDS ...............................................................................................................i 6.1 Introduction ...................................................................................................................i 6.2 Mud Properties..............................................................................................................i 6.3 General Mud Programme for North Sea Drilling ......................................................... iii 6.4 Spud Mud.................................................................................................................... iii 6.4.1 Freshwater/Polymer, Seawater/CMC................................................................. iv 6.4.2 KCI/Gypsum (KCI/Gyp) ...................................................................................... iv 6.4.3 Salt saturated mud (SSM) .................................................................................. iv 6.4.4 Super saturated mud (K/Mg). ..............................................................................v 6.4.5 Salt dolomite mud (SDM) ....................................................................................v 6.5 Oil-Based Mud (VCM) ..................................................................................................v 6.5.1 General ...............................................................................................................v 6.5.2 Safety measures ................................................................................................ vi 6.5.3 Coparex regulations ........................................................................................... vi 6.5.4 Spacer design - high-density VCM..................................................................... vi 6.5.5 Sampling procedures for average oil on cuttings analysis ................................ vii 6.5.6 Hydrogen sulphide ............................................................................................ vii 6.5.7 Drillstring corrosion ............................................................................................ ix 6.6 Handling and Storage ............................................................................................... xix 6.6.1 Handling ........................................................................................................... xix 6.6.2 Storage............................................................................................................. xix 6.6.3 Solids Control................................................................................................... xxi 6.6.4 Solids control guidelines by interval ................................................................. xxi 6.6.5 Spudding In ...................................................................................................... xxi 6.6.6 Chalk formations ............................................................................................. xxii 6.6.7 Clay and shale formations...............................................................................xxiii 6.6.8 Salt and other formations ................................................................................xxiii 6.6.9 Operating guidelines for solids control equipment ......................................... xxiv 6.6.10 Hydrocyclones............................................................................................... xxv 6.6.11 Centrifuges................................................................................................... xxvi 6.7 Lost Circulation ....................................................................................................... xxvi

Illustrations

Figure 6.1 Corrosion theory .....................................................................................................x Tables

Table 6.1 General mud programme for North Sea drilling ...................................................... iii Table 6.2 Corrosion trouble shooting table .......................................................................... xvii Table 6.3 Minimum chemical stocks (mud maintenance only) .............................................. xx Table 6.4 Geological layout .................................................................................................. xxi

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7. DRILLING FLUIDS

7.1 Introduction Numerous drilling problems in the North Sea area have lead to the development of a large number of diverse drilling fluids. For environmental reasons water-based muds are the preferred system. Versa Clean Muds (VCM/oil-based) must only be used as a last resort to overcome specific drilling/hole problems. The major functions of drilling fluids are: •

Primary well control. The hydrostatic head of the mud column has to safely control the formation pressures.

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Cooling and lubrication of the bit.

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Cleaning of the bottom of the hole.

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Cuttings removal from the hole.

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Transmitting hydraulic power to the bit in order to increase penetration rates.

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Stabilising of the wellbore.

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Providing corrosion protection for the work string.

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Help to evaluate drilled formations.

7.2 Mud Properties Mud properties are controlled by the type and amount of solids in the mud and their chemical environment: •

Density (S.G.). The density can always be increased with barite. Do not allow drilled solids to be the source of increased weight. To decrease density use solids control equipment or dilute with water if necessary.

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Funnel Viscosity (seconds). Viscosity is normally increased with the addition of bentonite or viscosifying polymers. To decrease use water dilution, thinners and solids control equipment.

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Plastic Viscosity (cps). This is dependent on the solids content and is the result of friction between particles. The addition of gel will increase the plastic viscosity. Reducing solids will decrease plastic viscosity.

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Yield Point (pascals). Increase the yield by additions of viscosifying polymers or high yield bentonite. Decreasing the yield point can be accomplished with the use of thinners or by dilution.

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Gel Strength (10 seconds, 10 minute pascals). To increase gel strength use bentonite or viscosifying polymers. Decrease by reducing solids (especially fines) and preventing hydration of clays and shales.

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pH. Increase pH with additions of caustic, potassium hydroxide, soda ash or lime (depending on the type of mud system). Decrease with mild acidic products or with dilution.

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Fluid Loss (cc). To reduce fluid loss use specially designed polymers or starch in combination with carefully controlled solids content. Bentonite in fresh water will assist in

reducing fluid loss. Dispersants reduce fluid loss but effect rheology (YP) and solids build up. •

Calcium Content (mg/L). To increase calcium content add gypsum or lime. Reduce by adding soda ash or bicarbonate of soda.

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Chloride Content (mg/L). Increase with sodium chloride or potassium chloride. Decrease with dilution.

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Solids Content (volume per cent). Barite, bentonite and drilled solids all result in increased solids content. Reducing solids can be achieved by flocculation, mechanical removal and dilution. Minimising hydration by the use of an inhibited mud system will help control the production of fine solids, and is therefore effective when attempting to run a low solids system.

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MBT (Methyl Blye Test - kg/m3) This test determines the amount of reactive bentonite type solids in the mud and this is determined by measuring the cation exchange capacity of the solid particles. The MBT will increase when drilling bentonite clays or shales, or whenever gel is added. The MBT will be decreased whenever very fine solids are removed by dumping or dilution. It is necessary to measure the MBT in order to determine the amount of drilled solids in the mud system.

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Oil Content (volume per cent). Oil may result in increased penetration as a result of torque reduction. However, oil may act like additional solids and reduce the drilling rate when torque is not a problem.

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Torque/Drag. Reducing torque and drag may be accomplished by adding oil, oil substitutes, surfactants, and a variety of other torque/drag reducing products. If the torque/drag problem is due to filter cake build-up, reducing the fluid loss may be necessary.

7.3 General Mud Programme Table 6.1 lists the general mud programme. Table 7.1 General mud programm e General

Stratigraphy

Mud type

hole size 32" 16"

North Sea Group

Seawater/C MC

24" 12 1/4"

Chalk, Altena and Trias Groups

Seawater/C MC KCI/Gyp

121/4" 83/8"

83/8"

Trias (containing Roetsalt) and Zechstein (without mixed salt layers)

SSM

Zechstein (with mixed layer salt)

K/Mg

Rotliegend and Limburg Groups

SDM

Average mud composition

Drillwater base with 80 kg/m3. Bentonite 1 kg/m3. Caustic Soda and Seawater with 15 kg/m3. CMC HV or PAC 1 kg/m3. Caustic Soda. 3 Seawater with 15 kg/m . CMC HV/LV or Trias Groups PAC R/LV 1 kg/m3. Caustic Soda plus Lignosulphate and Barytes. Freshwater with 20 kg/m3. Bentonite 50-100 kg/m3. KCI 20 kg/m3. Gypsum 15 kg/m3. PAC R/LV 2 kg/m3. KOH plus Barytes. Water with 330 kg/m3. NaCl 40kg/m3. Bentonite 1 kg/m3 Caustic Soda 15 kg/m3. PAC R/LV or CMC HV/LV plus XC Polymer, Baryte or Dolomite and Zinc Carbonate. Brine with 80kg/m3. Mg ion 40 kg3. K ion 300 kg/m3. Cl ion 25 kg/m3. Starch (mod.) plus XC Polymer, Barytes, "Kemseal" and Iron Oxide. Seawater with 50-80 kg/m3. NaCl 20 kg/m3 Bentonite 1 kg/m3. Caustic Soda 15-20 kg/m3. PAC R/LV plus XC Polymer, Dolomite and "Kemseal".

7.4 Spud Mud Three types of spud mud are used to drill the surface hole. Freshwater/Bentonite (FWB), Seawater/CMC (SWC) and Freshwater/Polymer (FWP). All are designed to drill in the North Sea Group, although the FWB and the SWC are used when there is a high sand content in the surface interval and the FWP when there is a high clay content. The intention is to produce a high viscosity mud with good solids carrying capacity, and therefore good hole cleaning ability. Other benefits are that when drilling less consolidated formations the spud mud will provide good wall cake properties for greater hole stability (particularly in the bentonite based muds). See the general mud programme for mud composition. Spud mud properties The actual required mud properties will be given in the drilling programme.

Average properties: SD: Viscosity: Fluid loss:

<1.15 60-100sec.Mf <10.

7.4.1 Freshwater/Polymer, Seawater/CMC Designed to provide a relatively cheap and easily maintained mud system which provides some hole stability improvement over a basic gel system. Generally the spud mud is used as a base for the system. Primarily used to drill the chalk group (chalk, limestone and marl), the cretaceous formations (claystone, marl and sand), the jurassic formations (claystone, marl and non-reactive clay sections) and the upper triassic formations (claystone and marl, but not if large salt sections are predicted). The required mud properties will be given in the detailed drilling programme.

7.4.2 KCI/Gypsum (KCI/Gyp) Designed to provide an inhibitive environment to swelling clays (provided by the potassium ion) and greater solids control (provided by the flocculation of sub-micron clay particles by the calcium ion). Generally used to drill the same intervals as the Freshwater/Seawater Polymer muds but is programmed if intervals of reactive clays are predicted. It should not be run if large salt section are predicted. The required mud properties will be given in the detailed drilling programme.

7.4.3 Salt saturated mud (SSM) Designed to reduce the dissolution of salt layers through the saturation of the mud with the sodium ion. Only applicable if the less complex evaporates (salts) are predicted (e.g., carbonates, anhydride and halite). Used for drilling the Triassic/upper Permian formations in which mixed salt layers are not predicted. The required mud properties will be given in the detailed drilling programme.

7.4.4 Super saturated mud (K/Mg). Designed to reduce the dissolution of complex salt layers. The mud is saturated with potassium and magnesium ions which prevent the potassium and magnesium salts from dissolving. Also has an inhibitive effect on the less complex salts. Used when mixed salt layers are predicted in the zechstein formation.

Average properties: SD: Viscosity: Fluid loss: Mg2+: K+: Cl-: Pm:

as required (1.35 - 2.40) 45 - 100sec.Mf <1 - 5ml API 80g/l 40g/l 300g/l 0.1 - 1

The required mud properties will be given in the detailed drilling programme.

7.4.5 Salt dolomite mud (SDM) Designed to provide an optimal logging environment with very low water loss. The resistivity of the mud is reduced by the addition of sodium chloride. Dolomite is added when weighting of the mud is required as it is acid soluble. Used when drilling the Permian pay zones. The required mud properties will be given in the detailed drilling programme.

7.5 Oil-Based Mud (VCM) 7.5.1 General VCM’s are designed to minimise the transfer of water from the mud to the formation (osmosis), by balancing the salinity of the mud to that of the formation, generally by the addition of calcium chloride. The reduction of fluid loss stabilises problem shales and protects sandstones which have reactive clays in the pores. In addition to these benefits there are several others which have reactive clays in the pores. Unfortunately there is a high environmental penalty attached to the use of VCM’s. •

The VCM policy states: − The use of VCM is confined to the smaller hole sizes, i.e., 12 1/4" hole and smaller. − For offshore operations all VCM cuttings are transported to shore. − VCM will be used only if a suitable WBM cannot be found to drill the well, from a technical standpoint: • If the use of WBM may create formation impairment. • In horizontal hole sections. • In unstable hole sections.

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The proposed usage of VCM must be submitted to SodM prior to the well commencement, and approval granted before it may be used.

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Cost and time savings alone are not sufficient reason to justify the use of VCM. They must be supported by some of the above criteria.

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Reference can be made to the M-I Drilling Fluids Versa Clean Manual for detailed preparation and maintenance instructions on the current VCM system.

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If dry cuttings are being produced over the shakers, an effort should be made to feed the cuttings directly into the cuttings container.

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The cuttings container should be periodically inspected as it is sometimes possible to recover VCM using the mud vacuum.

7.5.2 Safety measures •

Personal protection: Appropriate gloves, glasses, filters, face masks, eyewash stations, and foot wash stations must be available.

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Rig modifications: Exposure to VCM vapours and aerosols must be restricted by: − Closed in shakers (sheeting, etc.). − An extractor fan installed above the shakers. − Mudpits closed off as far as possible. − All drains/discharge points are to be controlled with fluid content measurements taken prior to discharge.

All enclosed areas must be fitted with air circulation systems capable of keeping the air purity at an acceptable level. The critical factor is the maximum allowable concentration (MAC) valve of mud components (i.e., oil vapour etc.) in the air. •

The following information and warning notes must be displayed on notice boards and on special warning signs at strategic places on the rig while using VCM. − VCM will be in use during the present drilling programme. − VCM contains substances that, under certain circumstances, can be dangerous to your health. − All drilling personnel must take the following precautions: • Avoid skin contact. This can cause irritation of the skin, (or in the longer term inflammation or eczema). • Avoid inhaling excessive quantities of vapour or oil mist over a prolonged period. − Modifications have been made on this rig to ensure a safe and healthy operation. Ventilation is adequate at places where vapours are created.

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All drilling personnel will follow the safety rules associated with VCM: − Wear the prescribed protective clothing and equipment. − Take the necessary precautions when using materials and equipment to decrease the risk to drilling personnel. − Contact medical services if you have any health problems.

7.5.3 Company regulations Reference should be made to the Company H.S.E policy regarding the protection of the environment . 7.5.4 Spacer design - high-density VCM To achieve efficient removal of weighted VCM’s or invert emulsion fluids, the following spacers have proven to be successful. They have resulted in the minimum amount of waste generated by providing an efficient sweep and the minimum amount of mixing.

1. 5m3 Viscosified water. SG:1.85. 2. 10m3 Seawater + 10 % KLEEN UP. 3. 5m3 Viscosified Water. SG: 1.03.

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To reduce the quantity of contaminated seawater produced displacing VCM, the following technique should be considered. Stop circulation after the chaser behind the VCM is seen at the surface. Allow the remaining oil to segregate and collect in the DPCSG annulus. This small amount of oil can then be disposed of properly onshore, and the seawater can be disposed offshore if it contains less than the required 40ppm.

7.5.5 Sampling procedures for average oil on cuttings analysis As all VCM cuttings are shipped to shore it is not an operational requirement that the average oil on cuttings remains below the legal requirement of 100g oil per 1000g dry material (10 percent oil on cuttings). However, it is important to minimise the volume of cuttings shipped in order to reduce disposal costs and to save mud. The cuttings wash system is now used for this purpose. The wash fluid has been replaced by VCM and the system acts as a mud recovery system, recovering the VCM lost through the solids control system. Testing for average oil on cuttings is to be performed periodically to ensure that the wash system is operating effectively. To determine the average oil content the following sampling procedure is used. The procedure ensures that a representative sample of the total disposal flow is taken for analysis. 1. When a cuttings treatment system is used with one central/combined exit* point, then only sampling at this exit point is needed. 2. If more exit points exist, then sampling at each exit point must take place. 3. The frequency of sampling while drilling is every hour and the quantity shall be approximately one-quarter of a litre or half a kilo. 4. After 12 samples have been taken, the samples are homogeneously mixed to approximately 6kg. From this mixture a sample is taken for the retort analysis. If the bit is pulled before 12 samples are reached, the mixture should be made of the available samples. 5. Utilise lag time (of cuttings to surface) to determine the interval over which the samples have been taken. 6. If samples have been taken from more than one sample point, the mixing of the samples must be in proportion to the quantities produced by the different flows. In order to determine this ratio it is required to measure the output of each contributory piece of equipment over a period of 5, 10 or 15 minutes, depending on the rate of penetration. 7. Under no circumstances is whole mud allowed to be dumped. * An exit point is a discharge point to the cuttings transport container. Samples should be taken from the cuttings transport container, at regular intervals, for measuring the oil/mud content of the cuttings. This is to maintain a full check on the mud volume balance. 7.5.6 Hydrogen sulphide Special considerations must be taken when drilling potentially sour wells. These considerations cover both personnel and equipment protection. When setting up for a sour well the following areas should be addressed: •

Rig selection: Sour service equipment.

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Personnel training: All crews to have H2S training.

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Mud selection for the sour zone: Is H2S easily detected?

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Ambient air monitors: What is the expected H2S content?

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Type of monitoring equipment: H2S and kick detection.

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Drillpipe protection: Is it required?

Mud Type Selection H2S is soluble in many fluids used in the drilling industry. The two most common are water and oil. The type of fluid being used can affect the ability to detect H2S: Water: Water-based muds are preferred for drilling H2S as the H2S is detected more readily as it comes out of solution at the surface. In addition, a simple HACH test can be used for detecting the presence of soluble sulphides. Oil: VCM’s can be used for drilling sour zones, however they must be treated very carefully. H2S is extremely soluble in oil and may not be detected readily. This can make it extremely dangerous to the rig personnel at the surface due to H2S remaining in the mud system. One benefit of using VCM is that it coats the drillpipe and substantially reduces the susceptibility of the pipe to H2S attack. Scavenger Pre-treatment The decision to add a scavenger as a pre-treatment should be weighed carefully against the following: 1. H2S Content If only a small amount of H2S is anticipated, and no special detection equipment will be available, then it may be desirable to scavenge the H2S immediately. In this case only a small amount of scavenger will be required. When larger amounts of H2S are anticipated and they are not being scavenged out with simply a pre-treatment, then no pre-treatment should be used. It is much more efficient to treat out larger amounts of H2S with chelated zinc which will not adversely affect the mud properties. 2. Cost In most situations very little H2S will actually be drilled due to the hydrostatic overbalance of the mud. In these situations there is no benefit to pre-treating the mud. The pre-treatment may actually cause more mud problems than the benefit gained through pre-treatment.

Detection Capability When H2S is expected in quantities that could be hazardous to either personnel or equipment, it is not possible to pre-treat with enough scavenger to eliminate the problem without causing major problems in mud rheology. In most instances it is usually better not to pre-treat as the mud properties are not affected and the H2S can be readily detected by a drop in pH at surface, and by the presence of soluble sulphides in the mud. Typically it is better to know that a problem exists than to mask it until it becomes more severe. If pretreatment is desired then zinc carbonate is typically used due to its low cost. Typical pretreatment concentrations are 2-5kg/m3. H2S Detection and Monitoring

When H2S is expected in quantities that could be hazardous to either personnel or equipment, a detection program should be in place. H2S can be detected readily and dealt with as follows: 1. pH: The pH should be monitored on a regular basis (several times per tour). If a drop in pH is observed it may be due to an influx of H2S. In critical situations it may be desirable to have a continuous electronic pH probe located at the flowline. If a drop in pH is observed, a check for soluble sulphides should be made immediately. 2. Soluble Sulphides: A HACH test for soluble sulphides should be made on each tour. In critical situations it may be desirable to confirm the HACH test data with a Garrett gas train test. 3. H2S Monitors: In addition to the ambient air monitors, mud loggers may also have a mud duck located at the flowline. Mud ducks should only be used as an indicator as they are prone to error. The pH and sulphide tests should be the primary detection methods. 7.5.7 Drillstring corrosion Drillstring corrosion is one of the most expensive problems faced by the drilling industry. In addition to the replacement cost of steel tubulars, corrosion is responsible for a large percentage of the tubular failures experienced during drilling operations. Proper practices and detection methods performed at the rig site can go a long way towards preventing these costly failures.

Figure 7.1 Corrosion theory

Anode The anode in an electrochemical reaction is the portion of the cell which loses material, especially where pitting is observed. Material is lost from the anode by going either into solution or through oxidation. The chemical reaction is as follows: Feo -----> Fe++ +2e-(electrons) Cathode During the corrosion process one material has the current flow toward it and thus has material deposited upon it. The cathode is the pole which has material deposited upon it. The rate of deposition is dependent upon the difference in electrical potential between the anode and cathode. On steels the usual chemical reaction occurring at the cathode is as follows: No Oxygen 2H+ + 2e- ----> 2Ho + H2 gas Oxygen Present (Most Common) O2 + 2H2O + 4e- -----> 4OHSteel Steel used for drilling tubulars is composed primarily of iron and iron carbides. The iron carbides give the strength to the steel and exist within the steel matrix as small microislands. The iron carbides have a slightly lower potential than the surrounding matrix, thus they act as a cathode and the steel matrix acts as the anode. It is this property of steel which makes it susceptible to corrosion. If the steel is in contact with an electrolyte (water or mud) then a current will be set up between the millions of cells located upon the surface of the steel and corrosion will be possible. Current Flow The rate of corrosion is a function of the amount of current flowing between the anode and the cathode. The strength of the current is primarily influenced by two factors: 1. Electrolyte Strength: The composition of the drilling mud plays a major role in the amount of current that can flow between the anode and cathode. If there is a high concentration of ions in the mud (i.e., salt-based mud), then the mud will be very conductive to electricity. 2. Electrical Potential: The electrical potential between the anode and the cathode is the greatest determinant of how fast a material will corrode. The difference between the iron and iron carbides within the steel matrix is small when compared to the difference between metals such as zinc and iron. Oxygen Enhanced Corrosion When iron is exposed to oxygen and water (electrolyte) the iron reacts with the oxygen to produce iron oxides (rust). As the rust builds up on the surface of the steel, an electrical potential is created between the steel which is no longer exposed to oxygen and the steel which is exposed to oxygen. The steel below the rust becomes an anode and metal loss occurs below the rust. The metal loss can cause very large pits to form. The same process

can occur below pipe protectors and other attachments on the drillpipe if they are not moved frequently, or the pipe is not protected with an inhibitor. Microstructure Corrosion Even when oxygen is not present in the mud, corrosion can occur due to current flows between individual cells within the steel matrix. The iron carbides within the steel matrix have a lower potential than the iron. This allows localised metal loss to occur on the surface of the steel. The electrical potential of the steel can also be affected by the localised steel properties such as hardness. Localised stress points such as slip deformations can act as anodes which lose metal to the surrounding steel matrix. This type of stress can be typically seen on a drillpipe in the slip areas and in the upset regions. •

Types of Corrosion The types of corrosion can be broken into several categories. Forms of corrosion which are common in drilling operations include: 1. Erosion. Erosion corrosion is due to material loss from fluids passing the drill tubulars at a significant velocity. This type of corrosion is usually limited to the inside of the drillpipe due to the velocities experienced. Although the rate of corrosion will be very small, time can cause the total erosion to be significant. Plastic coating of drillpipe can help to reduce this type of corrosion significantly. 2. Oxidation. If the level of dissolved oxygen is not kept low in the mud, then oxidation of the steel can occur. If a local corrosion cell is allowed to remain, severe pitting can occur with this type of corrosion. This type of corrosion can cause local stress points in the steel which may lead to crack initiation and propagation. 3. Electrochemical. Electrochemical corrosion is the most common type of corrosion experienced in drilling operations. When the drilling mud has a large number of free ions available (i.e., salt muds) then an electrolyte is available to allow current flow between the anodes and cathodes on the surface of the drillpipe. Any tendency for the drillpipe to corrode will be aggravated under these conditions. If any other corrosive conditions are present, such as dissolved oxygen, CO2, etc., the corrosion will be magnified even greater. 4. Carbon dioxide. Carbon dioxide (CO2) in the mud can cause severe corrosion. CO2 is soluble in water and causes the pH to drop. When the pH drops carbonic acid is formed which attacks the surface of the steel. An additional problem with CO2 is that calcium carbonate scale may be deposited on the drillpipe. When this occurs corrosion may be accelerated in a process very similar to the oxidation process. If the pH is maintained above 11 the solubility of CO2 is greatly reduced. 5. Hydrogen Sulphide. Hydrogen sulphide (H2S) may enter the mud from drilled formations or from bacterial degradation of mud additives such as starch or lignosulfonates. The H2S reacts with the steel to produce iron sulphide and atomic hydrogen as follows: H2S + Fe+2 -----> FeS + 2H+ The hydrogen is free to enter the steel matrix due to the small size of the atoms. Once in the steel the atomic hydrogen combine with other atoms to form hydrogen gas (H2). The hydrogen gas molecule is larger than the individual hydrogen atoms and causes large stress concentrations within the steel. These stress concentrations are frequently large enough to cause crack propagations and catastrophic steel failure.

In addition to the hydrogen embrittlement, the iron sulphide (FeS) will also set up a corrosion cell on the surface of the steel which may lead to severe pitting. 6. Stress. Localised stress points in a steel matrix often become areas of localised corrosion. The differing metal hardness and strengths in high-stress regions tend to have a slightly higher electrical potential than the surrounding steel matrix. If an electrolyte is available a corrosion cell will be set up and localised pitting will occur. This type of corrosion can typically be found in the following areas: • Slip region. • Drillpipe upset (internal and external). • Tong marks. • Dents and mashes from pipe stabbing. 7. Fatigue. Fatigue stress occurs when a large number of stress cycles occur in a steel. This stress may be caused by drillstring vibrations, shock loading at the bit, etc. During each stress cycle a small amount of residual stress may build up until a crack is initiated. In addition, the continual stress cycles may lead to work hardening of the steel. If the steel becomes too brittle it may fail more easily under downhole stress conditions. If other forms of corrosion are associated with a higher stress point in the steel, a point for crack initiation may occur. Fatigue stress can lead to catastrophic failures. •

Causes of Corrosion The following are the primary sources of corrosion in drilling operations: − Soluble salts: When free ions are available in the mud a current flow can be readily set up between anodes and cathodes on the steel surface. − CO2: When dissolved in water the CO2 forms carbonic acid and causes the pH to drop. This will result in pitting. − Oxygen: Dissolving oxygen in water is the most corrosive condition encountered in most drilling operations. Oxygen accelerates corrosion by depolarising the cathodes and by directly attacking metal at the anodes. − H2S: This gas can cause catastrophic failure of steels through hydrogen embrittlement and will also cause pitting. − pH: If the pH of the mud is too low (<10.0 - 11.0) several types of corrosion such as salt, CO2 and H2S will be accelerated.

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Corrosion Prevention Although all of the sources of corrosion cannot be eliminated at the drill site, several practices can be adopted to help prevent corrosion: pH control: When the pH is kept above 11, the rate of corrosion is reduced dramatically. Increasing the pH of the drilling mud will help to prevent several types of corrosion. 1. Electrolytes: At pH's above 10.5 the rate of corrosion is reduced dramatically. 2. CO2: At pH above 9.5 the solubility of CO2 is reduced dramatically, thus the ability to form carbonic acid is reduced. The use of lime is recommended as it precipitates the CO2 out as calcium carbonate. If caustic is used it forms a sodium carbonate which may cause mud problems as the concentration rises. 3. H2S: At pH's above 10.0 the solubility of H2S is reduced. Lime is recommended for pH control. Caustic should not be used by itself as it reacts with the H2S to form sodium sulphide. The sodium sulphide is soluble in water and will release H2S gas if the pH drops. The use of lime is recommended as it forms calcium sulphide which is

not as soluble and may precipitate out of the mud. An additional benefit of the lime is the free hydroxyl ion which helps to maintain a high pH. Oxygen: Reducing sources of oxygen to the mud system will help to reduce corrosion. If the oxygen content is still too high or a salt-based mud is being used, then oxygen scavengers will be required. The following practices can be utilised to reduce sources of oxygen at the rig site: 1. Hoppers and mix pumps: These items are usually the largest sources of oxygen. Do not leave these pieces of equipment running when they are not in use. 2. Mud guns: Do not use mud guns unless absolutely necessary. The use of mixing paddles is recommended. 3. Solids equipment overflow: Equipment such as desilters and centrifuges should have their discharge points below the surface of the mud tanks. 4. Mechanical degassers: If air entrainment in the mud is a problem then the use of mechanical degassers should be considered. 5. Mud properties: High viscosities and gel strengths cause the mud to be unable to release entrained air at surface. If thinning the mud will not cause hole cleaning or stability problems, then it should be done. Degasser Procedures: When gas cutting of the mud is experienced, the blow-out preventers are immediately closed and normal circulation maintained through the coke lines (choke wide open). The mud gas flows into the side of the degasser. A vent line leads from the top of the degasser to a safe distance from the mud stream and the gas can be vented out with safety through the line. The mud containing residual gas then passes out the bottom and is drawn into the degasser. The degasser operates under a vacuum and by allowing the mud to flow over a series of baffles, is capable of extracting virtually all the remaining gas. Vacuum in the degasser is maintained by a jet on the discharge side of the degasser and by a vacuum pump mounted on the top. The vacuum pump discharge should be vented at a safe distance from the rig and flared if necessary. A partition in the mud tank between the intake and the discharge of the degasser separates the gas cut mud from the degassed mud. The jet is operated by the standby mud pump. Normally, after circulating for a few hours with the blow-out preventers closed, the amount of gas will decrease to the point where the BOP's can be opened and drilling operations can be resumed. The degasser will continue to be employed until the mud is gas-free. This may require up to one or two days of more or less continuous operation. If the gas cutting exists for periods in excess of this, a small amount of weight material will usually be added to the mud. This will normally eliminate the continuous type of gas cutting, although trip gas may still persist. The trip gas is, of course, handled with the degasser and, if severe, the BOP's are again closed and the flow turned through the choke. Prior to starting a round-trip, the mud weight in the bore-hole has to be sufficient to create enough over balance onto the formation pressures. Oxygen Scavengers

If the oxygen content in the mud cannot be eliminated with normal practices at the rig site, then it must be removed chemically. The most effective method is through the use of catalysed sodium sulphite. It is essential that excess sulphites (50-100 mg/l) be maintained at the flowline. It is also essential that the catalysed sodium sulphite be added with a chemical injection system directly into the pump suction line to prevent oxygen contact with the product. The removal of oxygen alone will not completely prevent corrosion. It is normally necessary to add a filming amine or other corrosion inhibitor to properly protect the drillpipe. Corrosion preventers The addition of corrosion control agents may be necessary to keep the corrosion to an acceptable level. After all sources of oxygen contamination have been minimised, then a corrosion inhibitor should be added to the mud. This is particularly important when drilling with saltbased muds which are more prone to corrosion. The following corrosion preventers are typically used: 1. Filming amines: These materials coat the entire drillpipe. 2. Phosphate esters: These materials only attack the anode sites, thus preventing material loss. However, if the coating is not 100% complete the actual corrosion rate at localised areas may increase. 3. Barrier layers: There are several products which prevent corrosion by forming a corrosion product on the steel surface which prevents further contact between the steel and the mud. However, the majority of these chemicals are no longer environmentally acceptable. Drilling conditions: As the depth of a well increases and the temperature and pressure increase, the likelihood of corrosion occurring increases rapidly. Corrosion rates are affected by both the temperature and the pressure: Temperature: The rate of corrosion for all types of corrosion increases with increasing temperature. As a rule-of-thumb each 30o C rise in temperature doubles the corrosion rate. The most common cause of temperature increases in the circulating system is increasing formation temperature with depth. Another source of temperature can be circulating friction pressure. This pressure drop is converted to energy in the form of temperature. High circulation rates and small nozzles can cause circulating temperatures high enough to cause significant increases in the corrosion rate. Pressure: Increasing pressure will reduce the solubility of acid gasses such as CO2 and H2S, however if the gasses are present in the mud they will become soluble as they are circulated to surface with the reducing hydrostatic pressure. For this reason pressure should not be considered as an effective corrosion control device.

•

Corrosion Testing Several techniques are available to test for various types of corrosion. The most common techniques used are as follows: General Corrosion Corrosion rings - downhole measurement of corrosion.

Corrosion rings are typically placed in the crossover between the drill collars and drillpipe, and in the saver sub to allow a downhole and surface corrosion rate to be read. Ensure the grade of the corrosion ring matches the grade of pipe in the drillstring. The rings should be left in the hole for a minimum of 40 hours. Normal drilling operations require that the corrosion rate be kept below 50 mils per year (mpy). It is extremely important the rings be handled carefully to ensure accurate readings. Handling procedures are as follows: 1. Do not remove the ring from its packing until immediately before installation. 2. Clean the box end of the tool joint to remove all mud and dope. Place ring in the tool joint recess with the bevelled edge facing down. Do not damage plastic coating. 3. Record the well location, depth in/out, date in/out, and time in/out on the packing slip. 4. Run the ring for a minimum of 40 hours and remove carefully. Clean the ring and apply a light film of grease or oil to prevent any further corrosion on the ring. Place the ring in a sealed container and ship immediately to the mud lab. Galvanic Probe - Continuous mud pit measurement. These probes provide a real time measurement of the corrosion rate in mils per year (mpy). They are very accurate, however they must be constantly cleaned or they will not be reading from fresh mud. The normal point of installation is in the possum belly of the shaker where the mud flow helps to maintain cleanliness. Newer styles of probes are now equipped with ultrasonic cleaners and can be placed in one of the mud tank compartments. Typical drilling operations should realise a corrosion rate of 50mpy or less. H2S Corrosion HACH Test - Rig site test for soluble sulphides. This test is a simple test for soluble sulphides which can be performed quickly at the rig site. If sulphides are detected then there is H2S present in the mud. These tests are not extremely accurate and should be backed up with a Garrett Gas Train measurement when sulphides are detected. Garrett Gas Train - Specialised lab/field test for soluble sulphides. The Garrett Gas Train (GGT) is an extremely accurate measurement for soluble sulphides which indicate the presence of H2S in mud. Although the test is normally run under laboratory conditions, it can be used in the field in special circumstances (i.e., critical sour gas wells).

pH Probe - Periodic or continuous pH measurement. The pH of mud can be measured manually or with electronic probes. If a drop in pH is observed it may be due to H2S in the mud. If this is the case then the mud should be checked for soluble sulphides. Pre-stressed Bearing - Cracks evident in pre-stressed bearings. Pre-stressed bearings are frequently installed in the shaker compartment of the mud tank. These bearings are extremely susceptible to hydrogen embrittlement. When exposed to H2S they crack readily. This test should only be used as an indicator of H2S and should be backed up with further testing. CO2 Corrosion pH Probe - Drop in pH without any sulphides present.

The pH of the mud can be measured manually or with electronic probes. If a drop in pH is observed it may be due to CO2 in the mud. If this happens then the mud should be checked with an alkalinity test for carbonates. Alkalinity Test - Free carbonates present. The alkalinity of the mud can be measured with a series of titrations. If free carbonates are present then there may be CO2 in the mud. Table 7.2 Corrosion trouble shooting table Problem Oxygen

Source Surface mixing

Visual Clues Pitting & deposits

Test Method Acid soluble

Mineral scaling CO2

Formation Formation

White scale Pitting w/blk film

Acid soluble Alkalinity

H2S

Formation

FeS & pitting

HACH

Treatment Oxygen scavengers & filming agents Scale inhibitor Raise pH & treat out carbonates Chelated Zinc

Oxygen Oxygen is the most significant component in most types of corrosion and accelerates many other types of corrosion such as attack by acid gasses or chlorides. Oxygen is entrained in the mud by additions through mixing systems, solids control equipment, etc. High viscosity muds will also cause air to become entrained in the mud. Mineral Scaling This type of corrosion can lead to premature drillpipe failure, high pumping pressures and well control or fishing problems (i.e., inability to run wireline tools). CO2 This type of acid gas can cause corrosion through both a pitting attack (acid) and through scaling of calcium carbonate onto the drillpipe. H2S The primary concern with H2S is the sudden failure of drillpipe through hydrogen embrittlement. However, this type of acid gas can also cause corrosion through longterm acid attack causing severe pitting. In extreme cases corrosion may also be caused by deposits of elemental sulphur scale. Surface Mixing The primary cause of oxygen corrosion is through air entrainment in the mud. The majority of the air enters the mud through solids control and mixing equipment. Formation (mineral scaling) The majority of scale is caused by the precipitation of formation material onto the surface of the drillpipe. Most scales are composed of calcium compounds, however many are also due to soluble salts and minerals. Some scales can also be caused by the precipitation of mud materials as pressure and temperature conditions change. Formation (CO2)

Almost all natural gas contains trace to high percentages of CO2. This CO2 will form carbonic acid which will cause severe pitting of the drillpipe if not treated promptly. Formation (H2S) The vast majority of H2S comes from drilled formations. Small amounts of H2S can also be generated from the breakdown of certain temperature-sensitive mud products such as starch and linosulfonates. Pitting and Deposits Whenever an anode and cathode are present, oxygen will aggravate the corrosion rate. Corrosion due to oxygen is usually typified by moderate to severe pitting. A brown to red scale (rust) is typically present in a static condition. During dynamic drilling conditions where there is too much wear to allow a rust film to remain, the pitting may be present as a very clean corrosion point. White Scale The vast majority of scale deposits are due to calcium carbonate or salt. These deposits are typically white and very hard. Pitting With Black Scale Acid corrosion from CO2 results in moderate to severe pitting. The pits are typically coated with a dark brown to black film. Iron Sulphide and Pitting Pitting due to this acid gas is usually coated with a dark blue to black iron sulphide film. Acid Soluble Oxidised corrosion products are soluble in 15% HCl. However, the rate at which they dissolve will be very slow. Acid Soluble The carbonate scale should be readily soluble in 15% HCl. An immediate effervescence should occur. Alkalinity The alkalinity test will determine the amount of free carbonates in the mud. The usual source of these carbonates is drilled CO2. HACH This simple test will indicate if there are any free sulphides in the mud. The typical source of these is H2S. If free sulphides are detected they should be confirmed with a Garrett Gas Train test for sulphides. H2S contamination can also be detected by measuring the mud pH. If H2S is anticipated and a pH drop occurs, it could be caused by an H2S intrusion. Oxygen Scavengers and Filming Agents If careful management of oxygen contamination at the rig site is insufficient then it may be necessary to scavenge out the oxygen. The best method is through the use of catalysed sodium sulphite. To ensure that there is no oxygen in the mud, a 50-100mg/l excess of catalysed sodium sulphite should be maintained in the mud. The effectiveness of the treatment should be measured with corrosion rings. If corrosion is still occurring or the corrosion rate is not even (i.e., pitting on the rings) then the sodium sulphite should

be assisted by using a filming agent. The two most common are amines and phosphates. Scale Inhibitor If scale is forming inside the drillpipe while drilling then scale inhibitors can be added to the mud to prevent scale crystal growth. The most common chemicals are phosphate derivatives such as polyphosphates and organic phosphates. Chelated Zinc Although several products are available which are effective at scavenging H2S from drilling fluids, chelated zinc is the preferred method. This is due to the fact that this product has very little effect on the other mud properties. The more common additives such as zinc carbonate will cause carbonate contamination of the mud if large amounts are used. This can lead to increased viscosities and uncontrollable rheology. Typically, 1kg/m3 of chelated zinc will treat out 100mg/l of sulphides. Raise pH and Treat Out Carbonates When carbonates (CaCO3) are detected, the first line of defence should be to raise the pH, as this will keep the bicarbonate ion in the form of carbonates which can be readily treated out. The use of lime (Ca(OH)2) is the recommended treatment. The lime will provide a ready source of calcium ion which will precipitate the carbonates out as calcium carbonate (CaCO3). It will also provide hydroxyl ions (OH-) to maintain the pH. It is essential that pilot tests be performed with the mud prior to treatment to be absolutely certain that the problem is actually a carbonate problem. If the mud is overtreated, then the excess calcium may cause the mud to become flocculated. Typically, 0.13kg/m3 of lime will treat out 100mg/l of carbonates. •

Offshore drilling units (which have not previously used VCM) must be inspected by the Company Representative to establish their effectiveness in critical areas.

•

The Company Representative should ensure that there is adequate ventilation in the areas where drilling fluids are being used, and that notices are placed at strategic locations advising the precautions to be taken.

7.6 Handling and Storage 7.6.1 Handling All mud products require a valid SHOC card. •

Mud product containers must be correctly labelled.

•

SHOC cards for all products on location must be kept at the work site.

•

Mud products are to be handled in accordance with the safety regulations.

7.6.2 Storage On-board the rig mud chemicals will be stored: •

In the sack store.

•

In the watertight containers on the main deck.

•

In large bags on the main deck.

Special care must be taken when storing caustic soda. It must be stored in permanently closed steel containers with clear warning signs painted on the outside. These containers shall be stored in a safe place. See Table 6.3.

Table 7.3 Minimum chemical stocks (mud maintenance only) Product Bentonite CMC LV CMC HV Flocgel CAS Flocgel EHV XC Polymer Staflo Exlo Staflo R Barytes Dolomite Magnesium-Chloride Potassium Chloride Sodium Chloride Potassium Hydroxide Lime Caustic Soda Gypsum Sodium-bicarbonate Aqua Magic Mikhart (3 grades) Mica coarse/medium/fine Walnut Shells (2 grades)

Citric Acid Defoamer CDM 791 Calcium Chloride Pipelax LVO 69 Versamul NS Versacoat HF Versawet NS Versa SWA Kleen up Base oil Ironite Sponge

Unit kg kg kg kg kg kg kg kg kg kg kg kg kg kg kg kg kg kg kg kg

SW/CMC 10,000 3,000 6,000

kg kg 1 1 kg 1 kg 1 1 1 1 1 1 kg

100,000

KC1-Gyp 5,000

2,000 6,000 2,000 100,000

15,000 6,000 2,000

K-Mg

3,000 2,000 2,000

100,000 30,000 15,000 6,000

SDM

2,000 4,000 2,000 100,000 30,000

100,000

10,000

2,000 3,000

VCM

3,000 3,000

3,000 1,000

1,000

1,000

4,500

4,500

4,500

3,000

3,000

3,000

3,000

3,000

3,000 3,000 250 1,000 1,000 400 500

3,000

3,000 3,000 250 1,000 1,000 400 500

5,000

250 1,000

250 1,000 1,000 400 500

3,000

4,000

3,000 2,400 2,000 1,200 800 600 60,000

7.6.3 Solids Control •

For detailed instructions, refer to manufacturers’ operations manuals for solids control equipment. These notes are provided as a general guide only.

•

Shakers and centrifuges are the primary solids control equipment used for conditioning drilling fluids.

•

Desanders and desilters should not be used to process any drilling fluid unless absolutely necessary.

•

The centrifugal pumps feeding desanders and desilters break solids into smaller particles, therefore making removal more difficult.

•

Cuttings washing systems are to be used to assist waste disposal control.

•

A polymer mixing and dosing unit is to be used to enhance solids control.

7.6.4 Solids control guidelines by interval Table 7.4 Geological layout Group North Sea Chalk Rijnland

Formation

Niedersachsen

Coevorden Weiteveen Zuidwal Volcanic

Delfland Scruff Central Graben Altena

Upper Germanic Trias Bunter Lower Germanic Trias Zechstein

Upper Rotliegend Lower Rotliegend Limburg

Holland, Vlieland

Kimmerdige clay Puzzle hole Brabant Werkendam shale Aalburg shale Sleen shale Keuper, Muschelkalk Rotliegend Main Buntsandstein Lower Buntsandstein Zechstein 1,2,3 and 4 Fringe Zechstein Zechstein Caprock Zechstein Salt Slochteren SS Silverpit claystone Rotliegend Volcanics, Basal Clastics Productive measures Coals Measures

Description Dirt, Gravel Chalk, Marl, Sand Sand, Sandstone, Claystone, Shale Clay, Marls

Clay Clay

Solids control Spudding In Chalk Formations

Clay and shale formations

Sand, Shale Limestone Marl, Shale

Claystone Salt Sandstone Claystone Salt Carbonates

Sandstone, Claystone Claystone, Sandstone, Volcanics, Basalt

7.6.5 Spudding In Shakers: •

Always run screen sizes as fine as possible.

•

Clean the screens if they blind or change to another size.

Salt and Other formations

•

Brandt: screen size S10/S20 (or S20/S40).

•

Thule VSM 100: screen size 10/25 (or/84,/105).

•

Derrick: screen sizes can range from 14 to 84, depending on hole size and capacity of shakers.

Desanders: •

Only run the desanders if necessary.

•

Calculate the optimum feed pressure.

Desilters: •

Only run the desilters if necessary.

•

During spudding in, large amounts of solids are expected, and therefore the largest size nozzles (17 mm) should be installed.

•

Calculate the optimum feed pressure.

Centrifuges: •

For maximum solids removal.

•

High capacity (15 to 20m3/hour).

•

Weir plates for a low fluid level (no. 115 or 118 - for a maximum drying time).

•

The RPM should be low (1500 - sand is easy to remove).

•

The differential should be the maximum (mode III - to convey as many solids as possible out of the machine).

7.6.6 Chalk formations Shale shakers: •

Due to the lower solids quantity and smaller particle sizes, finer mesh screens must be run, making sure the appropriate surface is covered with drilling fluid as described in 6.6.5 (Brandt I, S20/S40 or S40/S60 mesh; Thule VSM 100, 10/165 mesh; Derrick 50 to 175 mesh).

Desanders: not used. Desilters: •

Only run the desilters if necessary.

Centrifuges: •

For maximum fines removal.

•

Low capacity (5 to10 m3/hour), increase residence time.

•

Weir plates for a high fluid level (no. 112 - for a maximum settling time).

•

The RPM should be maximum (3250 RPM).

•

The differential speed must be lowered to increase the residence time (dependant on cuttings weight).

Polymer mixing and dosing unit: •

Enhances the centrifuge performance in long chalk sections where fines build up can occur.

•

This unit is available on a call-out basis.

•

The polymer mixing and dosing unit must be explosion-proof for offshore applications.

7.6.7 Clay and shale formations Shale shakers: •

Clay and shale formations have a tendency to plug the screens. If this happens the screens have to be cleaned regularly. (Brandt I, 10/20 or 20/40 mesh; Thule VSM 100, 10/165 or 230 mesh; Derrick, 24 to 84 mesh).


Only run if necessary.

Centrifuges: •

Long drying time: − Clay formations de-water badly compared to chalk formations. The centrifuges should be adjusted for a long drying time.

•

Medium capacity (10 to 15 m3/hour).

•

Low fluid level (weir plates 115).

•

Maximum speed is recommended for clay without sand, and claystone (3250 RPM).

•

The differential speed should be 50 or 70.

•

To convey a lot of solids out of the centrifuge the preferred mode is II or III.

7.6.8 Salt and other formations These formations are generally encountered when drilling the smaller hole sizes. Shale shakers: •

Fine screens can be run, making sure the screen surface is appropriately covered with fluid (Brandt I, 60/80 mesh; Thule VSM 100, 10/165 or mesh; Derrick, 50 to 84 mesh).


Only run if necessary.

•

Change the nozzles to the smallest size, except in the salt sections where it may be necessary to install the largest nozzles.

•

Calculate the optimum feed pressure and adjust the pressure accordingly.

Centrifuges: •

Normally not necessary to run all the time in these sections.

•

Low capacity (5 to 10m3/hour), increase residence time.

•

Weir plates for a low fluid level (no. 115).

•

The RPM should be maximum (3250 RPM).

•

The differential speed should be adjusted to the circumstances (weight of cuttings, flow rate, etc.) to obtain 50 or 70 dry cuttings.

7.6.9 Operating guidelines for solids control equipment Shale Shakers To ensure an optimum performance of the shale shakers, check if: − The shakers’ skid(s) are placed horizontal. − The speed and direction of vibration are correct. •

Brandt shaker: check to see if the rubber blocks are worn or torn and if so exchange all four blocks simultaneously. The speed and vibration of the shaker is controlled by a Vbelt, which must be of the right type and tensioned with 5-6 cm slack. Too much slack and the optimum speed will not be reached; insufficient slack causes the shaker not only to move up and down, but also sideways.

When operating properly, the shaker should have two-thirds of the screen area covered with fluid. •

Thule: the vibration speed is − fixed VSM 100 model − variable VSM 120 model

The pool height should be 0.5” high (up to 16” from the front discharge). •

Derrick: the vibration speed should be 1800 RPM for 60 cycles, producing 4.6 G's.

The surface area covered by mud should be up to the middle of the second screen at an angle of 3 to 5 degrees, unless stick clays are present and a flat deck maximises the conveying speed and unloads the screen quickly. The shale shaker screens are of the utmost importance. Efficient operation includes: − Screen selection. − Screen tensioning. − Screen area used. − Screen angle. − Regular screen cleaning. − Fluid not by passing the screens. •

Brandt I: circular motion shaker with double decks, screen sizes vary from S (square mesh) 8 to 120 or B (oblong mesh) 20 to 120.

•

Thule VSM 120: circular motion shaker with double decks. The screen sizes for the top deck are S60 to 200, for the bottom deck S60 to 250, B60 to 200 and TBC (tensile bolting cloth) 40 to 200. The bottom deck consists of four screens. The speed is variable

between 0 and 1800 RPM in 12 settings. The screen angle can vary for the top deck from - 3 to + 3 degrees, for the bottom deck 0 to 5 degrees. The VSM 120 is designed to operate with a shallow pool of mud over the rear of the lower screen. The following shakers have new screen technology consisting of double screens with a repair feature. •

Derrick: linear motion shaker with a single deck. The mesh sizes for Derrick vary from DC (double or layered) 14 to DX 250 for the SWG (sandwich screen panel) type of screen and from DX 38 to DX 250 for the PWP (matrix flex flow screen panel) type of screen. The single deck consists of three screens. The angle of this deck can be varied between 0 and 6 degrees.

•

Thule VSM 110: linear motion shaker with a double deck. Screen sizes range from 10 to 30 mesh for the top deck. The lower deck consists of four screens with sizes ranging from 52 to 200 TBC mesh. Screen sizes for the front two panels are 84, 105 and 145 mesh. The angle of the lower deck is fixed at 10 degrees. The angle of the upper deck is fixed at 0 degrees.

7.6.10 Hydrocyclones Desanders: to ensure optimum performance of the desanders. •

The optimum feed pressure at the inlet can be estimated by: P (bar) = 2.21* x S.G. of the feed.

Desilters: to ensure optimum performance of desilters, nozzle sizes can be changed. •

Desilter cones are available in different sizes: 1/2” and 5/8”.

•

The optimum feed pressure at the inlet can be estimated by: P (bar) = 2.21* x S.G. of the feed.

Note: * Based on 22.5m (+/-2m) of head. This will suffice for the majority of desanders and desilters. Check manufacturers' recommended head if in doubt. The pump impeller size should be adjusted to acquire the appropriate feed pressure. COMPANY practice is to adjust a valve in the feed line which results in increased impeller wear.

Troubleshooting: •

If the underflow is too small, the possible reasons are: − The underflow nozzles are blocked (i.e., solids overloading), and the nozzles have to be unplugged. − The underflow nozzles are adjusted too small. (The nozzles have to be adjusted for a conical spray). − Overflow header extends far below the bottoms of the hydrocyclones (results in a "slurp" discharge, due to high vacuum in overflow header). Fit siphon breaker-nipple extending half-way into suction header with +/-6" stick-up.

•

If the underflow is too large, the possible reasons are: − Low feed head, mud emerges from base of all cones as a smooth cone of mud. Check motor speed, impeller size/wear. − Underflow nozzles adjusted too far open.

− Not enough air entering underflow nozzles, and the solids choke-off nozzle which closes off air resulting in a rope discharge. (Fit siphon breaker.) If vacuum is large enough this will lead to "slurping" and no discharge. − Worn out vortex finder. Visual Check: •

The desilter is working optimally if the underflow leaves the cones in a conical shaped spray. If the solids load is too high, it is often impossible to get this conical discharge, and the underflow will leave the cones as a thick stream called roping.

7.6.11 Centrifuges To ensure optimum performance of the centrifuges, three adjustments can be made: •

Capacity (flow rate). With increasing amount of fluid being fed to the centrifuge, the residence time decreases and the cuttings being discharged will be very wet.

•

Fluid level (pool volume). Dictates the length of the drying beach in the conical part of the centrifuge. A long beach means a longer drying time for the cuttings. However, a low fluid level also means less time for the solids to settle out. With the fluid level one can balance the settling and drying times.

•

Differential speed. Is the difference between the scroll and the bowl speed. The scroll will always turn faster to convey the solids out of the machine. The difference is usually between 10 to 100 RPM. A low differential gives the solids more time to settle, but the capacity is then very low. Each adjustment made, affects the other two parameters. Usually an engineer must be called for making adjustments on fluid level and maximum speed; pump capacity and differential speed can be adjusted by the crew.

On every rig there are at least two centrifuges. It is possible to: − Set one centrifuge on maximum solids removal for mud weight reduction. − Set one centrifuge on maximum fines removal for viscosity reduction. Ensure the trip switch is correctly positioned.

7.7 Lost Circulation Losses will occur as soon as the drilled formations cannot withstand the forces exposed to them. Formations are not homogeneous and have stronger and weaker stringers, cracks, etc. Forces created by drilling actions are: •

Hydrostatic height of the mud column = Depth x mud SD 10

•

Surge pressures created whilst running tubular strings in the hole.

•

Mechanical forces whilst pressuring up the bore hole with the mud pumps. This can happen as soon as the annulus is bridged off by excessive amounts of solids, collapsed formations, etc.

To cure losses Lost Circulation Materials (LCM) are used. The selection of these materials is governed by the applicable hole section/formation interval. In the pay-zone (productive formation), acid soluble, lost circulation materials shall be exclusively used. For other formations there are no restrictions on the choice of lost circulation materials. Curing Losses: •

The first consideration should always be: can the mud weight be lowered safely.?

•

Seepage mud losses will mostly be cured by the mud solids and cuttings whilst drilling. Otherwise, a small LCM pill (ca. 5m3) can be circulated around whilst drilling. NOTE: When selecting a LCM to be used, remember the minimum opening size (i.e., bit nozzles) through which the LCM has to pass.

•

Mud losses greater than 10m3/hr. cannot be cured whilst drilling. A firm LCM pill (10 15m3) has to be spotted on bottom, and subsequently, the bit has to be pulled above the spotted pill. Try to keep the hole full by pumping mud into the annulus. Pump through the drillstring at intervals to prevent plugging up. This procedure of spotted pills has to be repeated until the losses are cured or other remedies have to be applied.

•

Total mud losses. In this case the mud volume in the mud tanks is lost very quickly and making enough fresh mud on board the rig is not possible. The well shall be kept as full as possible by pumping the available mud, and thereafter seawater into the annulus. Firm LCM pills (15m3 or more) have to be spotted on bottom frequently. Pumping of cement to bridge off the zone creating mud losses shall have to be considered. Therefore, an emergency stock of 30 tons bulk cement, along with the required additives, shall be kept on board whilst drilling.

•

On board the drilling rig there shall always be a stock of LCM (see Table 6.2 Minimum chemical stock). Different muds require different lost circulation materials.

•

Composition of LCM pills: − 10 - 15m3 viscosified mud (100 MF seconds). − A mixture of fine + medium + coarse LCM mixed up to the practical maximum the mud can accept. The mud engineer will advise further (acid soluble LCM might be required).

•

When it is known that weak formations have to be drilled, it is good policy to have LCM pills readily available on board. Volumes will depend on available tank space.

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Contents

7. DRILLING EVALUATIONS ..................................................................................................i 7.1 Introduction ...................................................................................................................i 7.2 Coring Procedures ....................................................................................................... ii 7.2.1 Planning .............................................................................................................. ii 7.2.2 Preparation and making up the core barrel......................................................... ii 7.3 Mud Logging Procedures .............................................................................................v 7.3.1 Mud Logging .......................................................................................................v 7.3.2 Total hydrocarbon detector (Total Gas) ............................................................. vi 7.3.3 Gas chromatograph .......................................................................................... vii 7.3.4 Definitions of types of gas responses ............................................................... vii 7.3.5 Portable Gas Detector........................................................................................ ix 7.3.6 Collecting samples ............................................................................................. ix 7.3.7 Sample Description ............................................................................................ ix 7.3.8 Pore pressure predictions using the ‘d’ exponent ...............................................x 7.4 Openhole Logging....................................................................................................... xi 7.4.1 Introduction ........................................................................................................ xi 7.4.2 Stuck logging tools ........................................................................................... xiv 7.4.3 Logging programs and requirements ............................................................... xiv 7.4.4 Open-hole logging tool types ........................................................................... xiv 7.5 Drill System Testing .................................................................................................xxiii 7.5.1 DST results .................................................................................................... xxiv 7.5.2 Drillstem test (DST) methods ......................................................................... xxiv 7.5.3 Drillstem test equipment.................................................................................xxvii 7.5.4 Wellsite preparation for drillstem testing ........................................................xxvii 7.5.5 Making up the drillstem test tools and running in ..........................................xxviii 7.5.6 Obtaining the test ........................................................................................... xxix 7.5.7 Pulling the tools.............................................................................................. xxix 7.5.8 Evaluating the results...................................................................................... xxx 7.5.9 Recommended safe practices........................................................................ xxxi 7.5.10 Typical drillstem testing bottomhole assemblies .........................................xxxix 7.5.11 Calculating water cushion requirements .......................................................... xl 7.5.12 Laboratory analysis of gas, oil and water samples ......................................... xli 7.5.13 Guidelines for multiple tests ........................................................................... xlii

Illustrations

Figure 7.1 Schematic of gas trap .......................................................................................... viii Figure 7.2 Nomogram for "d" exponent determination........................................................... xii Tables

Table 7.1 Characteristics of different callipers ...................................................................... xix Forms

Form 7.1 Well logging program (page 1 of 6) .......................................................................xliii Form 7.2 Log quality control check list (page 1 of 4) ........................................................... xliv Form 7.3 Service company performance evaluation ............................................................ xlv Form 7.4 Field data transmittal form .................................................................................... xlvi

5. DRILLING EVALUATIONS

6. Introduction Evaluation of a well is required to:

7. Determine if hydrocarbons are present. 8. Provide correlation with seismic and off-set well information. 9. Determine geological characteristics of the drilled formations. 10. Enable a proper reservoir evaluation. 11. Comply with the government regulations. This section is provided as a guideline to the Company Representative and is intended to supplement his technical knowledge and established drilling practices. The Company Representative responsibilities include: 12. Ensuring that all wireline and evaluation operations are conducted safely and in accordance with the mining regulations. 13. Ensuring that proper well control/blow-out prevention procedures and equipment are incorporated in all evaluation operations. 14. Reporting all operations and safety aspects. 15. Specifying shooting nipples and BOP requirements. The Company Representative has the responsibility for the quality of all information obtained from the evaluation operations. These responsibilities include: 16. Maintaining an up to date cuttings log. 17. Ensuring that the evaluation contractors arrive safely and are on site with sufficient time to carry out checks before commencing work. 18. Ensuring that the evaluation contractor(s) perform their tasks in a timely and safe manner. 19. Ensuring that quality standards are complied with such as mud logging and petrophysical logging. Quality includes the method of data acquisition, the resulting information, and the supporting activities. 20. Collection of all geological data and sample handling on the wellsite (e.g., sample catching, sample and core descriptions). 21. Ensuring the evaluation requirements specified in the well proposal/drilling programme are satisfied. 22. Ensuring that the relevant equipment quality checks are performed before commencing work. 23. Ensuring that recommended practices are followed by the evaluation contractors. 24. Monitoring contractors on their operational performance and reporting as appropriate. 25. Reporting all quality aspects of evaluation operations.

26. Coring Procedures 27. Planning Core planning procedures are:

Confirm the core point with the wellsite geologist. Order the Coring Service by specifying the following: 4. Location. 5. Hole size. 6. Depth. 7. Formation to be cored. 8. Length of core to be cut. 9. Outside diameter of core to be cut. 10. Full or rathole core (full hole core is preferred). 11. Type of core bit. 12. Drillpipe/drill collar connections and drillpipe pup joints required. 13. Type of Core Barrel. 14. Special core preservation (wrapping) procedures and transport. 28. Preparation and making up the core barrel Condition mud To prevent washing and invasion of the core mud should be conditioned to have a fluid loss less than 6 cc/30 min. If core erosion is still a problem (particularly in unconsolidated formations), consideration should be given to running a face discharge core bit. Strap pipe out of hole Drillpipe and drill collars should be measured on the last trip prior to commencing coring operations. If strap out measurements are different from tally, strap in with the coring assembly. Check drill bit Check the drill bit for abnormal wear such as undergauge hole and missing buttons. Run a cleanout trip with a junk basket if necessary. Run junk sub A junk sub may be run on the last pit run prior to the core point to remove any junk from the bottom of the hole. Close blind rams Close the blind rams and replace the hole cover to prevent anything from dropping down the hole. Check core bit Check the core bit for wear and ring marks. Agree on the condition of the core bit with the Core Company Representative prior to running in the hole. Core Barrel Assemblies The following are components of the conventional core barrel assembly:

29. Core bit Core bits are usually slightly smaller than the size of the hole being drilled. This size reduction can avoid wedging. The exception to this is the rathole core which is significantly smaller than the drill bit size. Core bits also vary in the size and quality of

diamonds used on the cutter head. This allows the optimum bit selection for the type and strength of formation being cored. Listed are several core bit styles commonly used: 15. Natural Diamond Core Bit Small 6 - 8 stone-per-carat natural diamond cast directly into a tungsten carbide matrix crown to provide a sharp, durable cutting structure in medium-hard formations. Natural diamonds provide maximum abraision resistance to maintain full gage hole and consistent core size to ensure smooth recovery and prevent jamming. 16. Strata (PDC) Polycrystalline diamond compacts serve as the cutters in all diamond compact coring bits. These synthetic diamond cutters may be positioned to achieve effective cutting action in a variety of soft to medium formations, providing improved penetration rates and increased core recovery. Natural diamond gage protection assures full-hole gage throughout the coring operation. 17. Geoset / Ballaset / Tripac Cylindrical, thermally stable, PDC cutters for drilling in hard, abrasive formations where high frictional heat is generated. 30. Core catcher sub 31. Core catcher The long skirt core spring ensures against tipping. Precise spring tension also reduces the possibility of core wedging. 32. Stabiliser sub All core barrels should be run with a stabiliser above the core bit. The stabiliser should be no less than 1/16” less than the core bit diameter. 33. Inner and outer barrel assembly Several types of core barrels exist. If a disposable inner barrel is required, ensure that the barrel material is suited for downhole conditions. Some of the types are as follows: 18. Conventional core barrel. 19. Rubber sleeve core barrel. 20. Plastic sleeve core barrel. 21. Aluminium sleeve core barrel. 22. Pressure core barrels. 23. Absorbent (sponge) core barrels. 24. Oriented coring. 34. Drop ball The drop ball principle allows drilling fluid circulation at full force through the inner tube. Cuttings are rapidly removed from the bottom before coring. 35. Thrust bearing A simple thrust bearing allows a full-floating rotating inner barrel. The bearing is lubricated by free flow of the drilling mud. 36. Safety joint If the core barrel becomes stuck, the safety joint assembly enables backing off of the core barrel which permits the inner barrel and core to be removed, allowing the outer barrel to be fished. 37. Drill collars

38. Jars Run jars above the safety joint. Check that the ID allows the passage of a drop ball. 39. Drillpipe to surface Normal tripping speed is to be less than 0.25m/sec (greater than 40 sec./joint) because of the close tolerance on the bit and the core barrel. Diamond or PDC core heads are easily damaged by running into bridges and/or reaming through them.

NOTE: The daily coring time analysis will include the time from the moment the drilling bit leaves the bottom until the time the drill bit is back on the bottom and drilling. If a bridge is encountered, pick up and wash/ream through the bridge. Pump through the bit at a higher rate (if possible higher than the section was drilled with) and slowly lower the bit down to the bridge. Flush as many cuttings from the hole as is possible. If the bit begins to take weight, pick up and start the rotating at 10 - 30RPM, and go back down gently. Ream through the bridge by fanning the core bit on the surface of the bridge.

NOTE: DO NOT REAM FOR MORE THAN 30 MINUTES. Pull out of hole and make a conditioning trip with a regular bit if reaming proceeds beyond 30 minutes. The following guidelines also apply to cleaning the bottom. These are general guidelines and thus experience in a particular area should take precedence:

40. The drillstring should be spaced out using drillpipe pups so that the kelly is highly positioned and no connections or the least number of connections will have to be made while cutting the core. A rig equipped with a top drive is preferred. 41. When the bottom is reached circulate the mud at a high rate to flush any junk above the bit. Touch the bottom twice with this high-circulating rate and then go to the bottom rotating slowly at 30rpm. Upon touching bottom reduce the circulating rate to normal. After the bottom has been circulated clean, the ball is dropped prior to cutting core. 42. Start coring with a low bit weight (0.5-1.0T). After cutting approximately 1m, increase weight to 2.0-2.5T and rotation to 70 to 90rpm. The core barrel operator will determine the exact bit weight, mud circulating rate, and rotating speed. 43. When the core is cut, or when it is necessary to make a connection, pick up and break off core. If the core will not break readily (less than 2.5T), take a strain on the drillpipe and rock (DO NOT ROTATE) the rotary table until the core breaks. The core barrel operator will determine the specific procedures for recovering core. CAUTION: ROCK THE ROTARY ONLY; DO NOT ROTATE 44. Upon recovering the core barrel at surface, lay out the core on the catwalk or deck in the order that it is removed from the barrel. The wellsite geologist and COMPANY Company Representative must be present when the core is removed from the barrel, cleaned and packaged. 45. DO NOT WASH OR STEAM THE CORE. Wipe excess mud off as soon as possible with a wet cloth soaked in the drilling fluid with all excess mud wrung out. Other methods may be used upon approval of the wellsite geologist or Reservoir Engineer. 46. Measure the overall length of the core. Enter the core interval and recovery details on the tour sheets.

47. Package the core in boxes, marking each box with well name, core number, interval cored, amount of recovery, meterage represented in box, box number and total number of boxes. 25. The boxes are to be numbered in sequence with box number 1 containing core from the top of the interval and the highest numbered box containing core from the bottom of the interval. The wellsite geologist and Company Representative must ensure that the core is properly placed in boxes to ensure the core does not become reversed. 26. Inside each box indicate the meterage and the top and bottom of the core section. 48. Ship the core directly to the appropriate laboratory as directed. 49. Special instructions on handling pressure, sponge, plastic sleeve, rubber sleeve and oriented cores will be included with the particular drilling programme. NOTE: H2S precautions to be implemented if the cored formation is suspected or known to contain H2S.

50. Mud Logging Procedures 51. Mud Logging Mud Logging is used to detect and identify all hydrocarbons carried back to the surface by way of the wellbore annulus. These values are plotted on a vertical scale giving a hydrocarbon profile of the formations that the bit has penetrated. The range of hydrocarbons that should be readily identified by using a gas chromatograph are as follows:

52. Methane

(C1)

53. Ethane

(C2)

54. Propane

(C3)

55. IsoButane

(iC4)

56. Normal-Butane

(nC4)

A standard service will include a Total Hydrocarbon Detector which does not discriminate the various gases but gives a total magnitude of all hydrocarbons present within the sample stream. For proper interpretation of results it is important to use the Gas Chromatograph and the Total Hydrocarbon Detector. The sample is taken from an agitator assembly (gas trap) which is positioned in the shaker box so as to agitate and separate the gases from the drilling fluid as efficiently as possible. The sample then passes through a drying unit and is pumped by way of a 1/4" diameter polyflow tubing into the gas detector and gas chromatograph for analysis. Mud logging is routinely carried out with one or two loggers:

57.

24-hour supervision requires two loggers.

58.

12-hour supervision requires one logger.

Mud logging companies routinely offer basic geologic sample evaluation as a standard feature of their service. Lag Lag is the amount of time that elapses from the moment when the bit penetrates a new formation until the moment when the downhole particles and/or traces of gas travel back up the wellbore to the surface. A rate of penetration is measured instantly; as soon as the bit increases or decreases its speed, the driller has input. However, samples from that particular formation may not be circulated up

for several minutes. The mud logger must keep this in mind as he correlates the data. Bit to surface lag times are accurately timed by the mud logger using the carbide "bomb" technique. There is also a lag in taking samples from mud at the shaker to running it through the gas detector in the lab (depending on the distance it may be a few seconds to one or two minutes). Reports / Hard Copy / Interpretation of Results Each logging company will have slight modifications in the hardcopy output that is made available to each customer. All calibration and raw data should be made available for examination upon request. At the beginning of each mud logging job the Company Representative should discuss with the mud logger what information is desired, and the time interval in which the information should be presented. Proper interpretation of logging data is the responsibility of the service company, and the method that each company uses to accomplish this is slightly different.

59. Total hydrocarbon detector (Total Gas) A Total Gas Detector samples a continuous sample stream of air/gas mixture from the agitator. This makes the gas detector an on-line, real-time evaluation tool. There are three basic types of detector elements used in mud logging gas detectors today. They are as follows: Thermal Conductivity is a balanced bridge assembly that detects variances in cooling of gases contained within the sample stream as it crosses the elements. These variations, when amplified and calibrated to known thermal responses of gases, give very reliable responses. Catalytic Filament Detection is accomplished through the use of a balanced wheatstone bridge. Half of the Wheatstone bridge is reading a reference air response. As gas is passed across the hot filament of the other half of the bridge circuit, a resistance imbalance occurs. This imbalance is amplified and recorded. Flame Ionisation is a process whereby hydrogen fuel is burned between positive and negative collector electrodes. As an outside sample source of hydrocarbon is introduced into the same flame, an imbalance in the amount of ions collected on each electrode is set up. This imbalance is amplified and recorded. Total mud gas readings are recorded continuously with a recorder chart. The gas readings are recorded for each logging interval and represent the gas response vs. depth. Since there is a lag between the time when a formation is drilled and the time when the sample reaches the surface, gas readings must be logged. Total gas measurement can be applied in three ways. First, it evaluates hydrocarbon shows. If the reading increases, hydrocarbons are present in a zone. The reading itself does not indicate productivity; however, increased readings in a potentially permeable, high-porosity zone often indicate the zone may be productive. Secondly, gas measurement detects pressure. Increasing background gas usually indicates increasing formation pressures. Connection gas and abnormally high trip gas usually indicate a nearly balanced mud system (hydrostatic pressure = formation pressure) or even an underbalanced system. Finally, the total gas reading curve can be correlated with other measurements, such as resistivity, ROP, spontaneous potential, and offset well curves. These correlations can provide input on potentially productive zones.

60. Gas chromatograph Analysis of hydrocarbon components is carried out with a gas chromatograph. Most service company chromatographs are rapid sampling, batch processing instruments that provide accurate proportional analysis of the paraffin series hydrocarbons from methane (C1) through pentane (C5). The basic difference between a total hydrocarbon detector and a chromatograph is that the chromatograph has a partition column that the sample is fed through and separates each gas by molecular size. The methane will emerge first, followed by the ethane, the propane, etc. These gases are then fed across a detector element and the magnitude of each gas is determined by comparing a response to that of a known calibration gas response. The Total Hydrocarbon detector has three basic element types used in the industry today. Thermal Conductivity is a balanced bridge assembly that detects variances in cooling of gases contained within the sample stream as it crosses the elements. These variations when amplified and calibrated to known thermal responses of gases, gives very reliable responses. Catalytic Filament Detection is accomplished through the use of a balanced wheatstone bridge. Half of the wheatsone bridge is reading a reference air response. As gas is passed across the hot filament of the other half of the bridge circuit, a resistance imbalance occurs. This imbalance is amplified and recorded. Flame Ionisation is a process where hydrogen fuel is burned between positive and negative collector electrodes. As an outside sample source of hydrocarbon is introduced into the same flame, an imbalance in the amount of ions collected on each electrode is set up. This imbalance is amplified and recorded. The SPWLA has set down standards of calibration for gas chromatographs. Calibration gas should be comprised of a mixture of methane (1%), ethane (0.25%), Propane (0.25%), Iso-butane (0.25%), and normal butane (0.25%) with a balance of air or nitrogen (98.0%). The SPWLA has determined that calculation of gas peak response could be done by peak response or peak area integration. Reporting magnitude of constituent gases should be reported in volume to volume proportions and/or any decimal multiple thereof. For example: percent, parts-per-thousand, or parts-per-million by volume.

61. Definitions of types of gas responses The following are basic types of gas responses that are recorded during drilling operations:

62. Background Gas 27. Liberated Gas is the gas which is mechanically liberated by the drill bit into the drilling fluid as the bit penetrates the formation. 28. Produced Gas is the gas produced into the drilling fluid from a specific zone in response to a formation pressure which exceeds the opposing effect of hydrostatic pressure. 29. Contamination Gas comes from neither liberation or produced gas, but is from outside agents. For example, oil added to the mud system. 30. Recycled Gas can be any of the above definitions and has been detected at least once, and then cycled through the wellbore annulus for re-detection. 63. Connection Gas 31. Connection Gas represents gas entering the mud stream while the pumps are off. When circulation is resumed, the gas will be depicted as a sharp peak on the detection instrument charts and will usually be recorded one bottomhole lag time

later. This occurs since the portion of the hole just penetrated is least subject to filter cake, and as it is very close to gauge it is easily swabbed. If a connection peak lags to an interval uphole, or there are two peaks, then the formation pressure of the upper interval is greater than the hydrostatic head. Connection gas values are also very useful in adding weight material to prepare for an approaching potentially overpressured, high-volume zone. The connection gas values would be watched closely for any increase not associated with the pumps being down for a longer than normal time, (i.e., running a survey, rig repairs, etc.). If this occurs, particular attention should be paid to drilling and circulating background values ensuring that neither increases. If there is a further relative increase in the following gas value connection this increase may be the result of an upward migration of gas from the underlying high-pressure formation. Mud density should now be increased to a point where the next gas value connection is reduced. Since the gas connection can be circulated up without drilling ahead, mud density can be increased as a function of true formation pressure and maintained in a slightly overbalanced state by utilising the available mud logging information. This method of gradual and controlled mud density increases can be of particular importance when there is a potential for lost circulation. If the mud weight required to maintain constant background and connection gas values reaches a point where, if a kick occurs, the added weight necessary to contain the kick would possibly result in losing circulation to another zone. Consideration can then be given to running a liner over the potential lost circulation zone. 64. Trip Gas 32. Trip Gas collects in the static wellbore during the tripping operation. While trip gas can often provide valuable "static hole" information, gas values can vary considerably due to swabbing. Like connection gas, trip gas is usually detected a full bottoms-up lag time after breaking circulation, due mainly to the fact that filter cake is at a minimum at the bottom of the hole. Excessive swabbing is indicated on the instrument's chart paper as a gradual build up of trip gas appearing earlier than a normal lag time.

Figure 5.1 Schematic of gas trap

65. Portable Gas Detector The Portable Gas Detector(total gas detector) is operated by the Geologist on location. Checks for the Company Representative:

66. The Company Representative must have access to the hard copy report at all times. 67. Hard copy should contain both the Total Gas and Penetration rate from the strip chart. 68. Hard copy should be retained in a neat and orderly manner so that posthole well evaluation can be done. 69. Company Representative should have access to service company that is supplying instrumentation to provide interpretation and service. 70. Company Representative may request calibration demonstrations with reasonable notice to the service company. NOTE: The sample procedure requirements are included in the drilling programme. 71. Collecting samples The analysis of the drill cuttings by the mud logger and the wellsite geologist provides information of the lithology, rock composition, rock characteristics, the presence of porosity, and an indication of hydrocarbons. In addition, the density of the cuttings can be used as an indicator for the determination of a formation pressure transition zone. The lithology log can be used to evaluate lost circulation problems, formation zone instability, and identification of faults causing hole deviation. 72. Sample Description The mud logger is responsible for describing the samples. The more commonly encountered rock types are described below.

73. Argillaceous Rocks 33. Clay - Complex, platy alumino-silicates less than 2 microns in size. Two basic types recognised are expandable (clays that swell upon contact with water, such as montmorillonites) and non-expandable (illites). 34. Claystone/Shale - Same mineral content and size as clays, but indicated by compaction and dewatering. In cuttings, it is difficult to distinguish between the two. Shale must break into plate-like particles. 35. Marl - Any clay rock (from clay to shale) with 35 - 65% calcareous content. 74. Arenaceous Rocks 36. Siltstone - Clay-based rock in silt-sized grains or quartz particles. Any rock or intermediate composition between clay-based and sand-based rock. 37. Sand/Sandstone - Pure sand grains or sand grains with a clay matrix. Grain-size is fine to very coarse, and angular to rounded. Grains are poorly sorted to well-sorted, and cementation is poor to good. 75. Carbonates 38. Limestone - Primarily calcium carbonate, is recognised by fizzing strongly with 10% HCl. Some appear granular, and there are a number of classifications. 39. Dolomite - Similar to limestone but with a substantial part of the calcium replaced by magnesium. There is less fizzing than with limestone. 76. Evaporates 40. Anhydrite - Calcium sulphate or gypsum. White when pure; usually soft.

41. Halte (Rock Salt) - Sodium chloride. Can occur in large domes or in layers. Soft and soluble in water. 77. Carbonaceous Rocks 42. Coal - Black or dark brown, vitreous carbon. May be hard and brittle. Also occurs as peats, lignites, and other forms of organic matter. 78. Accessory Minerals 43. Pyrite - Iron sulphide. A light brassy yellow mineral associated with all sedimentary rocks. Its hardness and chemical stability may cause drilling problems if it occurs in large quantities. 44. Glauconite - Dark green to black iron silicate related to the mica group. 45. Mica - Calcium, magnesium, and iron silicate, platy in appearance. 79. Pore pressure predictions using the ‘d’ exponent Some abnormal pore pressures can be predicted by using the “d” exponent. This method allows predictions of differential pore pressure increases between the normal pore pressure gradient expected and any abnormally pressured areas encountered. The method simply plots “d” versus depth. A trend develops in the plot which correlates with the normal pressure gradient. Any deviation in this trend signals abnormal pressures. The advantage in using this method is that the information can be obtained while drilling. The disadvantage is that for any degree of accuracy to be expected, several drilling parameters have to simultaneously remain constant. For example, the “d” exponent is derived from the fundamental drilling equation which relates penetration rate to weight on bit, rotary speed, bit size and formation drillability:

where:

P N

=

k(W/D)d

P N W D k d

= = = = = =

penetration rate in metres/hour rotary speed, r/min. weight on bit, decanewtons bit diameter, mm formation drillability constant drilling exponent

The equation can be greatly simplified if assumptions are made that the formation drillability is relatively constant and the rotary speed varies linearly with the penetration rate. When field unit conversions are added, the equation becomes: log__P__ 18.3N

d= log

6.8W

10000D

Further modification allows prediction of actual formation pore pressure rather than differential pressure. The modification incorporates the normal fluid gradient and the actual mud density in use at the time. This corrected “d” exponent, dc, is found by: dc where:

=

d x (normal mud density) (actual mud density)

dc d

= =

P N

= 4m/hr. = 85r/min.

drilling exponent corrected for mud density normal drilling exponent

Example:

W D

= 9 000decanewtons = 222mm log

d=

__4__ 18.3 X 85

log

6.8 X 9000

=1.66

10000X 222

Then if the mud density in use is 1 180kg/m3 while the normal pressure gradient expressed as mud density is 1 000kg/m3 the corrected “d” exponent is: dc =

1,000 x 1.66 = 1.41 1,180

The “d” exponent can also be determined by using Figure 7.2. A better pictorial representation is seen when dc is plotted versus depth rather than “d” versus depth. So the “d” exponent can be used to estimate either deviations from normal pressure gradients or a corrected “d” value can be used to predict actual formation pressures. The information needed to calculate “d” is obtained while drilling. As more and more “d” values are calculated and plotted versus depth, a normal pressure gradient trend is established. Then when “d” values start to deviate from this trend line, a possible transition zone to abnormal pressure may have been encountered. So long as all drilling parameters remain relatively unchanged, the prediction is acceptable. However, this method does not take into consideration any mud properties, bit type, flow states, bit and annular hydraulics, etc. Even so, this method does allow a good pictorial representation of pore pressures to be seen while drilling progresses.

80. Openhole Logging 81. Introduction Openhole logging is carried out to provide the petrophysical parameters required to evaluate the formations surrounding a wellbore. Evaluation of log data can provide information on lithology, temperature, pressure, hydrocarbon, water saturations, porosity, permeability, fluid type in porosity (oil, gas, water), resistivity and water resistivity. This data is collected through running a variety of logging tools in the wellbore. The engineer and the geologist require information concerning the lithology of the formations, the porosity and permeability of any potential reservoirs, as well as the type of fluid in the pore spaces. In order to provide this information a number of logs have been developed:

82. Resistivity To determine water saturation if shale volume and porosity is known. 83. Gamma Ray To determine rock type; i.e., shale, sandstone limestone, or dolomite.

Figure 5.2 Nomogram for "d" exponent determination normal mud density actual mud density

= =

normal pore pressure gradient converted into a mud density mud density in use

84. Spontaneous potential (SP): 46. To determine shale volume.

47. To indicate permeable zones. 48. To calculate Rw. 85. Neutron, density, sonic Used to find porosity and matrix composition and identify fluid-type. 86. Calliper To determine hole diameter. 87. Microlog To indicate permeable zones. 88. Lithodensity log (LDT) A newer version of the density log which has the added feature of being able to identify lithology. 89. Natural gamma ray spectrometry tool Measures naturally occurring gamma rays. It identifies the presence in varying proportions of potassium, thorium and uranium. 90. Dipmeter log To find the hole orientation and dip direction of the formation beds. 91. Repeat formation tester Measures formation pressure and obtains fluid samples. 92. Formation micro-scanner/fullbore Formation Microlmager Provides a detailed image of the borehole wall. The following guidelines should be considered when wireline logging. These are general guidelines and thus any experience of a specific nature should take precedence: 93. Hole conditioning: Run a wiper trip. Work any tight hole. Circulate the cuttings from the hole with the drill bit just off bottom. Condition the mud to run electric logs. Use pipe spinner to come out of the hole. Strap out of the hole prior to all logging jobs. 94. Mud sampling: A circulated mud sample from the well must be obtained. The sample must be taken from the flowline before any water or other additives are placed in the mud and saved in a CLEAN container for the logger. This sample should be used for determining the resistivity of the mud. Have the logger run a filtration test on the mud from this sample. Use the filtrate and mud cake from this test, and have their resistivities measured. DO NOT PERMIT THE USE OF CORRELATIONS FOR THIS INFORMATION. Keep mud samples from freezing. 95. Prior to any wireline logging job a pre-job/safety meeting must be held. The programme should be discussed by all key personnel.

96. Tools containing radio-active sources may be run on the first logging run in open hole if the hole conditions are favourable. 97. Dummy trips should be made as, and when hole conditions dictate. 98. The rigging up/down must be supervised by the Company Representative. 99. A down-hole tension tool is to be included in every logging suite. If a logging tool becomes stuck it can be used to establish whether the tool or the cable is stuck. 100.All radioactive tools must be transported in "clearly marked" special containers. It must be clearly indicated whether they contain radioactive material or if the container is empty. 101.Ensure that sufficient cable on the drum is available to log to the required depth. The logging company must submit the log-in cable history log upon request. 102.Depth discrepancies between driller’s depth and logger’s depth of up to +/-2 m per 1000 m are acceptable; discrepancies in excess of this should be investigated and reported to the area petrophysicist. 103.Stuck logging tools Stuck logging tools must be fished using the strip over/reverse strip technique. If a radio-active source becomes stuck it must be treated as an emergency incident. No attempt is to be made to break the cable at the weak point unless instructed to do so by the Company Representative. Do not exceed a line tension of 50% of the weak point breaking strength.

104.Logging programs and requirements For an example of the Well Logging Programme see Form 7.1 at the back of this section. 105.Log Quality Control Check List (Form 7.2). 106.Service Company Performance Evaluation (Form 7.3). 107.Field Data Transmittal (Form 7.4).

108.Open-hole logging tool types 109.Formation Resistivity Sedimentary rocks, when dry, will not conduct electricity. However, current will flow through the interstitial water made conductive by salts in solution. The most common salt ions are sodium (Na++), calcium (Ca++), Chlorine (Cl-) and sulphate (SO4-). If an electric logging tool emits an electric field, these ions will move carrying the current through the solution. If everything else is constant, the greater the concentration of ions the lower the resistivity of the formation water, and of course the formation. The presence of shale in the formation will also contribute to the electrical conductivity of the formation. The conduction of electricity in shale is an ion exchange process between charged particles of clay. The net effect of shale depends on the amount, type and distribution of the shale, and the nature and relative amount of the formation water. More than one resistivity measurement is needed because of the effects of invasion. The flushed zone resistivity (Rxo) next to the borehole is higher than the resistivity of the

uninvaded zone (Ro), because the mud filtrate in the flushed zone usually has a higher resistivity than the formation water resistivity (Rw) in the uninvaded portion of the formation. Occasionally, mud filtrate resistivity is less than the formation water resistivity. This may occur when a well is drilled with salt muds or at very shallow depths where the formation water is more likely to be fresh (less salty, higher resistivity).Effects of invasion cause the resistivity to vary close to the borehole. Sometimes it is high; at other times it is low, depending on the resistivity of the mud filtrate, the formation water, the water saturation, and the porosity. The farther the measurement is taken horizontally from the borehole (into the formation) the more nearly it will match the true resistivity of the formation. In electrical logging practices we measure formation resistivity or specific resistance which is a formation characteristic where: R = rA L R = resistivity in ohms-metre2/metre r = resistance A = area in metre2 L = length in metres 110.Resistivity Logs Resistivity logs are used to measure the resistivity of the formation. Resistivity logs only work in uncased holes: high resistivity = rock , oil, gas, drinking water low resistivity = shale, salt water Various types of resistivity logs in use are: 49. Normal Device and Lateral Device: E Log (Normal Device) The electric log, or E-log, are mechanically simple but are quite difficult to effectively interpret. A current of constant intensity is passed between electrode A, which is at the logging tool, and electrode B, which is at the surface. The resultant potential difference is measured between electrode M, which is also on the logging tool, and N, which is located at surface. Since the current emitted by A is constant, any variation in the voltage at M will be due to changes in the resistivity of the formations. The electrodes A and M, on the sonde of the logging tool, are separated by a distance called the spacing. Common spacings are 16" for the short normal, 64" for the medium normal, and 18'8" for the lateral log. Usually the greater the distance between electrodes A and M the deeper the tool investigates into the formation. The 16" normal has the shallowest depth of investigation, while the 18'8" lateral log has the deepest depth of investigation. These normal devices are used to read the formation’s apparent resistivity (Ra) or true resistivity (Rt). These tools are especially useful in locating water-oil contacts, water-gas contacts or gas-oil contacts. A lost circulation zone will also be apparent from the reading of the normal device, provided the drilling fluid has a different resistivity than the formation fluids.

50. Focused Electric Logs The focusing electrode tools are better than the resistivity tools (such as the SP, 16" Normal, 64" Normal or 18'18" Lateral device) in highly resistive formations, salt water muds, and in adjacent beds with large resistivity contrasts between them. In addition, they have a better resolution for thin to moderately thick beds. The focusing electrode tools are available with deep, medium and shallow depths of investigation. The focusing electrode tools include the spherically focused tools and the laterologs (the dual laterolog being most common). These tools are used to determine the Rt and Rxo. 51. Induction Log The induction log is most useful in wells with a fresh water drilling fluid and in formations with medium resistivity. However, the induction tool is also useful in wells that have been drilled with air, gas or oil-based drilling fluids. The induction logs have generally come to replace the conventional resistivity log. They were originally made to measure resisitivity in wells with oil-base drilling fluids and air or gas-filled holes. Induction logs are also focused to minimise the effects of borehole fluids and borehole size, invaded zone fluids and adjacent formation resistivities. The dual induction log has been developed for those areas that had lower porosities and deeper invasion. Induction logs have much the same application as the conventional resistivity logs. A standard induction log will consist of the SP curve, in the left-hand track, a deep induction curve measuring the Rid, the medium induction curve, measuring the Rim, and the spherically focused curve measuring the Rsfl. The Rsfl curve indicates the resistiviy of the flushed zone. The Rim curve indicates the resistivity of the flushed and invaded zones. The Rid curve indicates the resistivity of the uncontaminated zone and can be corrected or adjusted to give the true resistivity or Rt. The conductivity log is also useful in detecting abnormal pressures. As with the "d” exponent, the conductivity values of normally pressured sections develop a trend which will be usually a straight or slightly curved line. This trend line is caused by the conductivity values decreasing with depth. Shale compaction results in lower shale porosity, which in turn results in less interstitial water to conduct the induced current. The conductivity trend therefore, decreases with depth. Abnormally pressured shales though, will retain more water and will therefore act as a better conductor. The conductivity readings opposite abnormally pressured formations will increase. 52. Spontaneous Potential (SP) SP is generally included on the resistivity logs but it is not a resistivity measurement. The SP curve is a continuous recording (versus depth) of the difference in electric potential between a moveable electrode in the borehole and a fixed (zero) potential of a surface electrode. The SP curve is recorded in the left- hand track but cannot be recorded in an oil based drilling fluid or an air-filled wellbore because of the lack of electrical continuity between the SP electrode and the formation. Uses of Sp: 53. Detect permeable beds (a qualitative indication only). 54. Determine Rw, formation water resistivity. 55. Give an indication of the bed shaliness. 56. Locate the permeable bed boundaries and permit correlation of these beds. The magnitude of SP deflections is always measured from the shale line. Opposite a permeable formation, the SP curve shows deflection from the shale base line. In thick,

clean beds the SP deflection tends to reach an essentially constant deflection defining a clean line. Shut-down of rig generator distorts the SP curve. The Logging Engineer should be informed of any changes in rig power generation. 111.Microresistivity Logs Microresistivity tools are designed to read Rxo, the resistivity of the flushed zone. These tools are all very shallow reading. The electrodes are mounted on flexible pads pressed against the borehole wall, thereby eliminating most of the effects of the mud on the measurement. The following are Microresistivity Tools: 57. Micrologs The first microresistivity tool was called the microlog. On this tool, a pad carrying electrodes is filled with an insulating oil. The pad is pressed against the wall of the hole by the backup pad. The current flows along a path. The microlog is best used to indicate permeability and formation thickness in low to medium resistivity formations. 58. Microlaterologs The microlaterolog(MLL) is similar in operation to its big brother, the laterolog (LL). The tool carries small concentric electrodes on a flexible pad that is pressed against the borehole wall. The outer guard electrodes force the current into the formation and prevent short-circuiting by the mudcake. For this reason, the microlaterolog is used in high-resistivity formations. 59. Microspherically Focused Logs The MSFL uses the same principle of operation as the spherically focused log but on a smaller scale. It is also a pad device and is often combined with other measurements. The MSFL is helpful for very thin beds not adequately displayed by normal resistivity logs. 112.Sonic Log Interpretation A sonic tool has transmitters and receivers. The transmitters are pulsed alternately spherically outward in all directions. The mud column and the tool have slower travel times (sonic velocities) than the formations. The first sound energy to arrive at the two receivers is the compressional wave (P-wave), which travels through the formation near the borehole. The difference in the times at which the signal reaches the two receivers is divided by the spacing of the receivers. This time, recorded in microseconds per foot, is called sonic interval transit time(t) for the difference in arrival times between the two receivers. Sonic tools have multiple transmitters and receivers to compensate for sonde tilt, washed-out hole, and alteration of the rock properties near the wellbore due to drilling processes. The logs produced by these tools are called borehole compensated (BHC) sonic logs. If the interval transit time and the type of formation is known, and the porosity is uniformly distributed (intergranular as opposed to vugular or fracture porosity),the porosity can be determined. The lithology must be assumed to make an estimate. Shale has a strong effect on the sonic log. In shaly formations (Vsh>5%) the sonic porosity must be corrected for the presence of shale. Gas also has a strong effect on the apparent sonic porosity: it raises the apparent porosity. If gas-bearing formations are anticipated, at least one other porosity device, preferably a compensated neutron log, is

run. Finally, the sonic wave does not "see" the vugular and fractures porosity (secondary) as well as it "sees" the intergranular (primary) porosity. This lowers the apparent porosity in vugular and/or fractured formations. The Sonic Log is important to geophysicists to tie in seismic data. 113.Density Log 60. Measuring Density Density is the weight of a unit volume of a substance. 1cc of water weighs 1g, so water has a density of 1.0g/cc and limestone's density is 2.71g/cc. Formation or bulk density cannot be measured directly from the borehole. However, electron density can be measured by using Compton scattering reactions, and electron density is nearly the same measurement as bulk density. The density-measuring tool bombards electrons in the formation adjacent to the wellbore with gamma rays from a caesium source and Compton scattering takes place. The gamma rays are counted by two detectors mounted on a skid pressed against the borehole wall. The two detectors allow compensation for the effects of hole roughness and mudcake while the bulk density measurement is made. The newest generation of density tools measures the photoelectric absorption crosssection of the formations. The photoelectric effect is simply another way the formation reacts to the bombarding gamma rays. This reaction occurs at a much lower energy level than Compton scattering. By measuring the energy level of the formation reactions, it is possible to separate photoelectric reactions from other reactions. The photoelectric response is then used to help identify lithology. 61. Density Log Interpretation The density determined by the density tool is called bulk volume. The rock structure of minerals such as sandstone or limestone is called the matrix. The density of this structure is called the matrix density. This is the density that the tool would read if the formation had zero porosity. The bulk volume is equal to the sum of the matrix volume and the fluid volume contained in the pore space. Density logs have a choice of matrix presentation. Classic presentations are sandstone or limestone. If the matrix is known to be dolomite then a dolomite matrix should be chosen. If the matrix is in doubt use a limestone matrix presentation. 114.Neutron Log The original neutron tool bombarded the formation with neutrons from a chemical source in the logging tool. This tool could measure the response of the formation as a function of the number of hydrogen atoms present. Because most of the hydrogen present is in the water and oil, and because one or both of these fluids are present in the pores of the rocks, the porosity can be determined by counting the hydrogen atoms. The compensated neutron device uses two detectors to compensate for hole rugosity or roughness. In addition, it measures the ratio of the detector responses and converts this ratio to a linear porosity reading instead of the non-linear response of the single-detector neutron tool. 115.Gamma Ray Log (GR) The gamma rays that are measured with this tool are naturally occurring rays rather than induced gamma rays from a source, as in the density tool. These "natural" gamma rays emanate from radioactive potassium thorium, and uranium, the three elements that account for most of the radiation in sedimentary formations. Potassium and thorium are closely associated with shale (illite, kaolinite, montmorillonite), while uranium may be

found in sands, shales, and some carbonates. The gamma ray curve is almost unaffected by porosity and is an excellent indicator of shale. However, formations containing radioactive contaminants such as volcanic ash, granite wash or have formation waters with a high level of dissolved potassium salts will indicate a higher level of gamma ray similar to a shale or clay. Gamma ray logs are also used as the substitute for the SP log in cased holes or in open holes where the SP log is unsatisfactory. The gamma ray log can be recorded through casing or drillpipe so is very useful for correlation. The gamma ray log is often used with the casing collar log (CCL) to correlate the location of casing collars, packers, liner hangers, or other downhole equipment with the exact depth on the open hole logs. 116.Natural Gamma Ray Spectroscopy Log (NGS) The natural gamma ray curve has its source essentially in three radioactive isotopes: uranium, thorium and potassium. Thorium and potassium are usually found in shales and clays. Uranium compounds may be found in practically any formation. The natural gamma ray measurement has long been used as a shaliness indicator, but it can be misleading because uranium may be associated with both shale and reservoir rock. A better shaliness determination may be made from the thorium and potassium measurements. The clays (montmorillonite, illite, kaolinite) can also be identified with these measurements because different clays have different ratios of thorium to potassium. Table 5.1 Characteristics of different callipers Sonic

Arms 3

Phasing 120

Max Dia 406 mm

Microlaterolog Proximity MicroSFL

2

180

508 mm

4

90

558 mm

Density

2

180

Dipmeter

4

90

Short Arm Long Arm D Type E Type

Borehole Geometry

4

90

Dual Axis

2

180

Standard Special 406 mm

Remarks 3 Arms Coupled 1 Reading 2 Arms Coupled 1 Reading 4 Arms Coupled 2x2 2 Pair Reading 2 Arms Coupled 1 Reading 4 Arms Coupled 2x2 2 Independent Readings 4 Arms Coupled Idependent Readings 2 Arms Coupled 1 Reading

117.Bottomhole Surveys The hole diameter is usually recorded in conjunction with the following surveys: 62. Sonic log 63. Microresistivity log 64. Density log 65. Dipmeter log 66. Borehole geometry log

The readings given by different callipers, in the same hole, may be different depending on the calliper design combined with the hole cross-section. See Table 7.1 for the characteristics of the different callipers. 118.Calliper readings The mudcake is a good reason to have different callipers reading different values: 67. If the arm of the calliper is the blade type, it will cut into the cake and this arm will "ignore" the thickness of the mudcake. 68. If the arm is of the pad type, it will skid over the cake and the mudcake thickness will be taken into account. Assuming there is no mudcake, the reading of different callipers in a perfectly round hole will be identical. But round holes are not always the case. In clearly ovalized holes, 2 arm, 3 arm and 4 arm callipers will read different hole diameter values, mostly because of the way these arms are coupled together. If the logging tool is fairly free to rotate inside the hole: 69. Two arm callipers will ride using the larger diameter of the hole. 70. Four arm callipers will ride with one pair of coupled arms using the larger diameter of the hole. The following example shows different callipers in an ovalized hole: 71. The sonic calliper (3 arms linked together) shows an "average" hole diameter. 72. The density calliper (2 arms) is applied on the wall with strength. Its back-up arm will cut into the mudcake. It will orient itself to read the largest diameter. 73. The two independent callipers on the dipmeter clearly show the oval section of the borehole. Arm pressure is also quite strong and the mudcake will not be recorded. 74. The proximity calliper (2 arms) will probably orient itself to read the larger diameter, and its pads will skid on the mudcake. This is the case in the upper part and lower part of this section. In deviated wells callipers may partially collapse under their own weight and give readings that are too low. 119.Cement Volume Log This wellsite computed product can be easily computed after running a Dual axis calliper device. 75. Required Inputs: Four-arm calliper 76. Dipmeter 77. Borehole Geometry Tool 78. Density with Dual axis calliper 79. Outside diameter of the proposed casing. Desired length of casing to be cemented. 80. Outputs: Cement volume in cubic metres. Log indicating borehole area, bit size area and area of proposed casing (square metres). Integrated hole volume and cement volume (in depth track). 120.Dual Dipmeter By measuring the dip (the angle that the formation makes below the horizontal) and the

azimuth (the direction in which the bed is dipping) of the formations, a great deal can be inferred about the processes that moved the beds to their present positions. The dip of a bedding plane is represented by two components. The stratigraphic dip is the angle at which the sediment was originally deposited, and the structural dip is the result of subsequent tilting or deformation. The Dual Dipmeter tool features two side-by-side configured electrodes on each pad. Highly accurate information on tool deviation and azimuth is obtained from a triaxial accelerometer and three magnetometers. Borehole geometry and hole volume are determined from two calliper measurements 90 degrees apart. 121.Fullbore Formation Microlmager (FMI) In conductive muds, the FMI tool provides electrical images almost insensitive to borehole conditions and offers quantitative information, particularly for fracture analysis. The FMI provides complete fracture network evaluation. Processed borehole images and dip data are provided in real time with the MAXIS 500 unit. 122.Wireline Formation Tester An empty chamber is lowered until it is opposite the zone to be tested. The chamber has an opening so fluids can flow into it. A valve controls the opening, and a pressure transducer with a surface recorder measures the formation pressures. The opening in the chamber is in the centre of a rubber pad that is pressed against the formation. This pad seals out the mud in the wellbore and allows only formation fluids to enter the chamber. Once the seal is made, the tool is opened and fluids flow in. The flowing pressure is measured during this time. When the chamber is full, the pressure builds up until it approaches reservoir pressure. The tool is closed, the seal to the formation is broken, and the tool is pulled back to the surface. The contents of the sample chamber are measured and analysed, and the pressure build-up curve is used to calculate permeability and reservoir pressure. The permeability that is measured is the permeability very close to the wellbore, which may not be representative of conditions farther into the formation. However, the wireline tester can be of great value when it is needed or when permeability is fairly high and a full sample chamber is likely.

123.Repeat Formation Tester Permeability can be estimated from the recovery data and pressure recording of the RFT tools. The RFT is a wireline formation tester that can be set any number of times during a single trip in the well. At each setting depth, a "pre-test" is made in which small samples of fluid are withdrawn from the formation. During this pre-test the fluid pressure in the formation next to the wellbore is monitored until equilibrium formation pressure is reached. These pressures are recorded at the surface on both analog and highresolution digital scales. The pre-test fluid samples are not saved. However, after a successful pre-test in a zone of interest, a larger fluid sample can be taken and retained. In one trip, "virgin formation" fluid can be recovered from one test depth using a segregated sample technique, or two samples can be recovered from different depths. RFT recoveries can be analyzed to establish reservoir fluid characteristics such as oil gravity, gas-oil ratio, and water cut.

When set for a test, the rubber packer is hydraulically forced against the formation to provide a seal from the wellbore fluids. Formation fluids enter the tool through the probe, which is forced into the formation. When the tool is set, the pre-tests are automatically and sequentially activated. The lowflow rate pre-test withdraws 10cm3 of fluid from the formation by movement of a piston in Chamber 1. The second pre-test follows immediately and withdraws 10cm3 at a higher flow rate into Chamber 2. In permeable zones the two chambers are filled in approximately 25 seconds. In some cases, the high flow rate pre-test may be deactivated in low-permeability reservoirs to reduce the amount of fluid withdrawn and speed up the tests. During the retract cycle, the pre-test chambers are pumped closed. 124.Modular Formation Dynamics Tester The MDT tool performs a mini-DST on wireline. It can measure static pressure faster than any other tool of its type and it can collect more, and better, formation fluid samples in a single trip than any other sampling tool. Sampling pressure and pre-test flow rate and volume can be controlled from the MAXIS 500 service unit. The MDT tool collects formation fluid through a probe that is placed hydraulically against the borehole wall. Thus, the formation can flow into the sample chamber until hydrocarbon enters (determined by resistivity) and then the sample is taken. Controls from the MAXIS 500 service unit direct this fluid into any selected sample chamber. By equipping the tool with additional sample chamber modules, a large number of fluid samples can be collected in a single trip into the hole. This permits testing a number of different zones on a trip, or collection of a number of samples from a single zone. The MDT Tool can be many different tools, depending on what a particular test requires. Individual modules, each with a specific purpose, can be assembled in a variety of ways, right at the wellsite. 125.Casing Wear Evaluation Tools: 81. The multi-fingered callipers use 15 - 30 fingers to measure the I.D. of the casing for wear. The resolution is +/- 1/16 inch. 82. The magnetic tools detect variations in the magnetic flux fields and thereby determine wall thickness reduction. They are used for corrosion detection and leak detection (holes). 83. The electromagnetic tools can detect the actual depth of the casing defect, whether it is internal or external (pitting or grooves). This is accomplished by detecting flux leakage or eddy currents. 84. The current flow tools can detect areas of metal loss and can be used in dry holes or with dielectric fluids. 85. The acoustic tools use the strength of the returning signal to provide a qualitative measure of wear. 86. The imager tools use high-frequency sound and provide excellent resolution of the wall surface, but no thickness. 126.Sidewall Sampling 87. General Sidewall samples (SWS) are mainly used for lithological and geochemical analysis. Especially for the latter, unshattered samples are of particular importance as mud infiltration may carry microfauna and flora of all ages into the sample. The sidewall sample programme is prepared in the Main Office. In shales, samples are usually selected at 10-25m intervals (depending upon shale interval length); in sands, selection depends upon requirements. Upon receipt of the programme, the

Well Site Drilling Engineer should check the individual sample depths against the sands and mark them on the GR log. The Logging Engineer must then choose charge size (powder type), release ring and fastener length. Decision will be based on lithology, hole size and previous experience with similar formation types. 88. For SWS guidelines refer to the SIPM Production Handbook, Volume I, Chapter 3. 89. Where guns are to be preloaded prior to transportation to the rig, a proposed SWS programme should be provided to the logging company by the Company. 90. Samples should be taken from bottom to top. 91. Carrier wire and head ring should be checked before running in. 92. If the number of samples to be taken is less than a full gun (generally 30 shots), the number may be made up by double shots over zones of particular interest. 93. If the number of samples to be taken exceeds one full gun but is not sufficient for two full guns, the second run can be used to re-test the intervals of poor recovery from the first run. 94. When shooting permeable formations sampling on the run may be used to minimise the potential for differential sticking. 95. SWS should be closely supervised by the wellsite geologist or engineer to ensure samples are correctly numbered when cut loose from the gun, and that the samples are correctly boxed. 96. Whenever possible the samples should not be touched as this contaminates the sidewell core. 97. Samples should be intact and longer than 1/2” to be acceptable. If a double-shot was performed on one zone and the two recoveries are less than 1/2” each, they can be combined and accepted as one sample. If altering gun parameters does not provide better than poor recoveries, a lower acceptance criteria may be considered. 98. Reporting 99. During sampling and sample recovery a record should be kept giving shot number, depth recovery, accepted (yes/no), lost, misfire, empty or broken samples and a short sample description. One copy of this list is to be boxed with the samples, one copy to the Company and another retained at well-site for reference. 100.Sample jars should state well number, shot number and sample depth. Depth of sample must also be scratched on the lid with a sharp instrument. 101.Samples are to be transported to a Geological Laboratory specified by the Company Representative as soon as possible following recovery and packaging. 102.Lost SWS Bullets 103.If bullets are not recovered and a wiper trip is required, run in with a rockbit and junksub. Rotate and circulate past depths where the sampling was attempted. 104.On the bottom drill +/- 1 meter, if there is no significant torque, continue as per programme. 105.If torque indicates junk on bottom make a basket run and fish for the junk. 106.If bullets are not recovered, further sampling runs may be made without wiper trips but the guns must not be lowered below the point where bullets were lost.

127.Drill System Testing A properly conducted and interpreted Drill Stem Test (DST) is the best diagnostic tool other than a production test for the evaluation of a prospective zone. The reservoir information derived from a DST is based on the actual “insite”, flowing conditions and represent average values for the depth or radius of investigation. Thus, a DST will provide superior information to other reservoir data obtained from a core or log analysis.

The following vital reservoir information can be derived from a DST:

128.Initial reservoir pressure. 129.Average permeability (for the radius of investigation). 130.Radius of investigation. 131.Formation damage by drilling fluids and whether stimulation may have application. 132.The location and effect of nearby reservoir heterogeneities such as faults, fractures, permeability changes, or fluid contact. 133.An estimate of deliverability. 134.Nature of reservoir fluids. 135.Potential future production problems, i.e., sand production, sulphur deposition, hydrate formation, etc. 136.DST results 137.All original charts will be delivered to the testing company for detailed reading and preparation of the final test report. 138.A copy of the charts and test results will be immediately forwarded to Exploration Services by the testing company. 139.Drillstem test (DST) methods There are generally three DST methods:

Open hole testing on the bottom of the hole. This method is used as the well is drilled. The prospective zone is tested immediately after penetration by landing the test tools on the bottom, thus expanding the packers in compression. Two packers can be run in tandem for increased reliability. Straddle testing in open hole. This method can be used to test any interval in the open hole by hydraulically expanding a packer on each side of a prospective zone and testing the interval. Cased-hole testing through perforations. This is the most reliable method of testing a prospective zone, however, it is also the most costly as it requires setting and cementing the casing and perforating. Well control is safer during cased-hole testing, and allows higher differential packer pressures. This is the only method used in offshore exploration drilling. There are several variations of the above methods, e.g., testing an open hole section below casing with the packers set in the casing. The following points should be considered when conducting and planning a DST:

140.Service Company Selection In some situations, such as deep hazardous wells, consideration must be given to testing companies with special tools, experienced personnel, and experience in the area, etc. Often these factors will influence the selection of the testing company to be used. 141.Amount of Open Hole to be Tested In general, a more conclusive test is obtained by testing the shortest interval which is practical, e.g., if water is produced in the testing of a long interval, it is sometimes difficult to locate the portion of the interval which is producing water. It is usually best to limit the

interval to be tested to less than 20 metres. Another factor is that in testing deep gas wells, the test interval should be minimised to keep the gas influx left below the packer as small as possible. Gas influx below packers is just as dangerous on shallow wells. 142.Packer Type and Size Packer size is governed by the size of the hole to be tested. Packer type is determined by the well depth and hole conditions. A harder packer rubber is required for deeper wells which exhibit high temperatures. 143.Location of Packer Seat Open-hole packer seats should be selected in hard non-plastic formations such as hard sands, hard sandy shales, non-fractured lime or dolomite, or hard, dense non-fractured shales. Core and calliper log data, if available, will provide information on where to select a packer seat. Otherwise, cutting data must be used. A packer should never be set in an incompetent or sloughing shale zone above a prospective formation. 144.Top and Bottom Chokes Normally, bottomhole chokes are run on all wells. On very high production wells larger than normal bottomhole chokes and tool internal diameters are required to obtain a draw down. For deep wells, a bottomhole choke is required: 107.To limit the rate of gas produced, 108.To reduce the flowing pressure on drillpipe and surface equipment, and 109.To limit the differential pressure across the packer (200 - 280bar). The choke is normally 3/8” to 1/2” which is small enough to achieve the above, but large enough to avoid tool plugging. The top choke should be initially fully open and reduced as flow, pressure, unloading of the water cushion, and safety dictate. The pressure upstream of the surface choke should be recorded throughout the test together with the choke size. 145.Probable Length of Flow and Shut-In Periods. Where no guidelines are given the following times are suggested: Pre-flow - 5min., Initial Shut-in-90min., Final Flow -60min., Final Shut-In-180-min. Total time: 335min. (5.5 hrs.). Normal time requirements are 5-60-60-120. Normally two flow periods and two shut-in periods are required on a DST. The initial flow or pre-flow should be five to ten minutes in duration. This can be shortened if the air blow indicates a highly productive formation or lengthened if the air blow indicates a very tight formation. If there is no initial blow, attempt to reset the packers. The initial build-up period is normally six to ten times the pre-flow period. Usually a sixty minute initial shut-in is adequate. If a weak air blow indicated a tight formation and the pre-flow period was extended to more than ten minutes, the initial shut-in period should be extended to ninety minutes. A minimum of a 60-minute final flow period is used unless gas or fluid is flowed to surface. If gas is flowed to surface, the flow period is extended until a stable flow rate is attained. If fluid is flowed to surface, the tool should be shut-in immediately unless provision has been made for tankage to contain the fluid. If the pre-flow and initial shut-in

are extended, the flow period should be extended to two hours. When sour gas is flowed to surface, the tool must be shut in immediately. In testing a deep well, it may be necessary to shut the well in as soon as the water cushion reaches the surface so that there is no danger of drillpipe collapse. The final shut-in period for highly permeable wells should be equal to the final flow period plus the initial shut-in period. For medium and low permeable wells, the final shut-in period should be one and a half to two times the final flow period. 146.Pressure Recorders The pressure gauges should have a range equal to one-and-a-half times the expected hydrostatic pressure. There should be enough spare range to cover any shock pressures that may occur. A rough check on the gauge hydrostatic pressure can be made by comparing the pressure with the hydrostatic pressure calculated from the mud weight. If there is any doubt, then the gauges should be recalibrated and supplied with a revised set of calibration charts. The pressures from each recorder should also be compared carefully. The data sheet accompanying each pressure chart should be marked with the position of the gauge, the pressure gauge serial number, the clock serial number, the on and off time for the clock, as well as other pertinent well data. Each clock run should have a range approximately equal to one-and-a-half to two times the maximum reasonable time the tools are to be in the hole. A temperature recorder should be run with each DST. The calibration and recording of the thermometer should be checked. 147.Reverse Circulating Sub A reverse circulating sub should be run on all tests. It should be run at least nine metres above the top of the test tools. Care should be taken that it is not located opposite a gas sand. The hole should not be reversed out until such time as the packers have been unseated. 148.Safety Joint A safety joint should be run with the test tools on all tests. 149.Jars Jars should be run on all DST's regardless of depth. 150.Water Cushion On tests of wells with depths greater than 2 750 metres, a water or nitrogen cushion must be run. However, if high pressure or high volumes are anticipated on a shallower well, a cushion may also be run. The main purpose of a cushion is to minimise: 110.Caving of the formation and sticking of the anchor pipe, 111.Plugging of anchor perforations and the bottomhole choke, 112.Packer failure, and 113.Drillpipe collapse on deep wells. Enough water or nitrogen cushion should be run so that the differential pressure across the packer is in the range of 200 - 280bar. For a deep well, the collapse rating of the drillpipe is also to be considered when selecting the amount of water cushion. It should be remembered that the collapse rating of pipe varies considerably with the amount of tension in the pipe. 151.Surface Equipment The working pressure of the surface equipment should be at least equal to the expected

formation pressure. A remote safety valve should be installed on the drillpipe at surface. On deep wells, consider provisions for a high-pressure pumping unit to be able to pump down the drillpipe. The flare line should be drillpipe with a minimum 21/2” inside diameter (ID) and a burst rating in excess of 200bar. All surface equipment and flare line connections should be thoroughly checked and tested before running a test. The annulus should be continuously monitored during a test. The trip tank should be used for this purpose instead of visually watching the annulus. 152.Drillpipe Collapse and Burst The collapse pressure rating normally quoted for drillpipe is with no tension. As tension increases, the collapse rating decreases. Burst pressure rating does not decrease with tension. However, the burst rating which is usually quoted for new drillpipe must be reduced to allow a safety factor for pipe condition and other unknowns. In testing a deep gas well, it may be necessary to close the tool in before the water cushion is unloaded or, if not, to hold a backpressure on the drillpipe at surface to guard against collapse. It should also be noted that when testing a deep gas well, if the well is shut in at the surface before it is shut in down-hole, then extremely high pressures could be encountered at the surface. A bottomhole choke will only limit surface pressure under flowing conditions. 153.Drillstem test equipment Run the minimum amount of equipment necessary, but always include three pressure recorders, one of which must be an outside recorder, a pump-out sub, a safety joint, jars, a sample chamber, and a fail-safe head loaded with a trip bar for the pump-out sub. Always run dual conventional packers. Run single inflatable packers if calliper log indicates excessive hole size or if more than one test of common interval length is to be run on a single trip into the well. When running a straddle test, always run with a straddle by-pass assembly. Consideration should be given to running an outside recorder below the bottom packer to check on the communication from below the packer if there is a possibility of by-pass plugging. Other equipment, such as multi-flow equipment, tight hole subs, etc., is to be run only at the request of the head office. A separator and related surface equipment may be used if requested by the head office. Always run two shut-in tools, one hydraulic and one mechanical. Always request that the testing company be equipped with a centrifuge to evaluate oil recovery, and has a means of determining the salt content of recovered water.

NOTE: The salinity of the mud should be determined from a representative mud sample from the shale shaker tank prior to testing. 154.Wellsite preparation for drillstem testing The hole should be conditioned prior to running a DST by circulating and completing a dummy trip to check for fill on the bottom. It is not necessary to raise the viscosity or adjust the mud properties to test. If the dummy trip and circulating indicate little or no fill, the hole is ready to test.

Strap out of the hole prior to all tests. For tests run on the bottom, also check pipe tally as follows:

Before starting out of the hole, mark the kelly as it is with the bit on the bottom. Measure all the pipe not used for the test, i.e., the part of the kelly in the hole, drill collars, etc. Measure all tools and pipe picked up. The difference between that laid down and that picked up should give the correct spot on the last single to find the bottom with the test tools. For tests to be run off the bottom, pipe should be measured while running in the hole.

155.Ensure the correct tools have been delivered to the location and that they are in good condition. Check floor manifold and chicksans prior to running the test. Pressure test to at least the maximum anticipated bottomhole pressure. The flare line should also be checked and pressure tested to ensure no connections are leaking. 156.After the test tools have been made up, a sketch should be drawn showing the component parts, their lengths, and diameters. In addition, record details of the fishing necks, positions of the bombs, reverse circulating sub, and packer. 157.Making up the drillstem test tools and running in The Company Representative must supervise the measurement of the tail pipe and test tools. Ensure that each item in the test string is included as requested and in its proper place. Check condition of packers prior to and after test. Run the tools in slowly to prevent pressure surges on the formation. Running speed should be one minute or more per 27.5 metre stand. When making up the tool and pipe, measurements should be taken to ensure correct packer location and to permit the last joint of pipe added to be marked at the point where it should be flush with the rotary when the packers are correctly in position. This allows the tools to be eased into contact with the bottom of the hole and provides a check on the weight indicator (weight indicators alone may give a false indication). A similar procedure should be used for testing inside casing or straddle testing in the open hole. The mark should be positioned so that test tools will be correctly located and the surface control head is conveniently accessible on the derrick floor. The weight of the testing tool assembly should be recorded before running drill collars and drillpipe to ensure that the correct allowances are made when setting packers and for tool opening. On wells where deviation is a problem, "hole drag" should be checked before setting packers or opening the tool. When the bottom is reached, check the measurements to determine the amount of hole fill. Prior to running the test, make sure that the flare line is properly connected, secured, and free of obstructions. While running in, the drillpipe should be checked for leaks by observing whether or not air is flowing from the pipe. Test string displacement should be closely monitored in a trip tank as the tools are run in.

158.Obtaining the test If necessary, the annulus should be filled prior to opening the tool. A close watch on the annulus should be maintained when opening the tool. A sudden drop in fluid level indicates that the packer is not holding and an attempt to reset the packers should be made. A very slow loss of fluid is not serious since it is usually caused by loss of mud or filtrate to a fractured or porous zone above the packers. A constant watch should be maintained throughout the test and the mud level must be in sight at all times using the trip tank for filling the annulus. In the event that sour gas is flowed to surface, the tool must be shut-in immediately. Short duration, non-flowing, open-hole tests should not be permitted to exhaust gas or air to the atmosphere within the derrick floor. In the event of an emergency, flow lines should go to the flare boom and sufficient chicksans should be connected to the control head to permit the pipe to be picked up with minimum delay to close the hydraulic tool. A steel cable is attached to the control head, clamped to each chicksan, and onto the floor manifold. All electrical wiring must be in good condition. Drawwork engines should be at idle in order that hoisting power be available without delay. Gas flow rates should be measured and recorded at least every 15 minutes. A recording chart should be used with an orifice well tester. Obtain two samples of gas on every test. One sample is to be obtained shortly after the gas reaches the surface, and a second sample taken near the end of the flow period. The initial puff and air blow during pre-flow and flow periods should fall into one of the following categories:

159.Weak - steady, slow stream of bubbles on surface of water pail. 160.Fair - steady stream of bubbles from four inches or less below water surface. 161.Good - steady blow up to 30cm below water surface. 162.Strong - steady blow to bottom of bucket, and is usually turned down to flare line. 163.Very Strong - steady blow that lifts water out of the bucket. (Normally diverted to flare line.) Always record the number of minutes for gas or fluid to reach the surface, and whether it was on pre-flow or final flow.

164.Pulling the tools Any test where liquid hydrocarbons have flowed to the surface, or that is known or suspected to, contain liquid hydrocarbons, cannot be pulled at night unless the hydrocarbon is first reverse circulated out of the drillpipe. If a small steady flare appears and does not die shortly after shutting in the tool, the drillstring may contain oil. Use plugs when tripping out. When pulling a test, pay particular attention to hole filling procedures. Do not run the pump continuously. Stop every few stands to fill the hole. Ensure the mud level in the tanks is dropping proportionately to the amount of pipe pulled. Always use a trip tank when pulling a test. If a fairly long interval is tested, you should suspect a gassified mud column in the annulus. Extra care must be taken that the hole is properly filled.

Catch samples at the top, middle, and bottom of the recovered fluid column. Samples of recovered formation water must be sent to a laboratory for analysis and must be accompanied by a completed Standard Sample Identification Sheet. Oil samples are to be sent for analysis only if requested by the head office. Check the charts as soon as they are available. If the hydrostatic pressures are only slightly higher than the shut-in pressures, a well kick may be imminent, therefore start running the pipe in the hole immediately. If a long column (greater than 150 metres) is recovered, if oil flows to surface, or if it is necessary to pull a test containing liquid hydrocarbon at night, the hydrocarbon must be reverse circulated out of the drillpipe. Lay line to tank to receive fluid being circulated out. Run the pump slowly, prior to dropping the bar, to open the pump-out sub. DO NOT CLOSE THE BLOWOUT PREVENTER (BOP). Drop the bar to open the pump-out sub (POS). Record the time required for fluid in the drillpipe to reach the surface. Calculate the fluid level in the drillpipe using the recorded time, the displacement of the drillpipe and the pump output. i.e., Fluid Level (m) =

Time (mins.) x Pump Output (m 3/min) Pipe Volume (m3/m)

Total fluid recovery (m) equals depth of test minus fluid level. Monitor fluid return and record pumping time to changes in fluid-type to calculate number of barrels of recovery of each fluid (oil, mud, water, etc.). Obtain samples of each type of fluid.

NOTE: If pump rate is too fast, some of the pump output will divert out of the flow tee instead of downhole. Always reverse circulate if sour gas or oil is suspected.

165.Evaluating the results Pressure charts should be examined carefully, first to ascertain that the tool operated properly and did not plug, and secondly to determine if the pressures recorded during the test were accurate. The following key pressures should be accurately read from the chart:

166.Initial hydrostatic. 167.Initial flow. 168.Initial shut-in. 169.Final flow. 170.Final shut-in. 171.Final hydrostatic. The initial and final hydrostatic pressures should be equal to (depth x mud weight x 0.0098). The final flowing pressure if the air blow has died to nil during the flow period, should be approximately equal to the sum of (metres of salt water recovered x 10.2) + (metres of oil recovered x 7.9) + (metres of mud recovered x 11.3).

When a recorder has been run below the lower packer on a straddle test with a by-pass assembly, check the chart to ensure that the bottom packer was holding. If the bottom packer was holding, only hydrostatic pressure is measured; if the bottom packer was not holding, the chart will resemble other charts in the test string. Report the nature and amount of all fluid recovered. Centrifuge a sample of oil recovery to determine basic sediment and water (BS&W) content. Obtain resistivity and salt content of water recovery. Weigh a sample of mud recovered and check it against the weight of the mud in the hole to determine if it has been diluted by formation water.

172.Recommended safe practices Pre-test Safety Meeting Operators shall hold a pre-test safety meeting with all personnel that may be involved with the drillstem test. This meeting shall review the testing plan, testing procedures, test prognosis, operation of surface equipment, designation of essential personnel, and responsibility of the personnel.

NOTE: The pre-test safety meeting shall be recorded, along with a record of those who attended the meeting. The pre-test safety meeting will include a discussion of the emergency response plan where applicable, including any revisions or recommendations to accommodate the specific well environment. 173.Mud should be checked to ensure mud properties are correct. 174.Fill-up lines will be installed on the drilling nipple above the blow-out preventer (BOP) to keep the casing full of mud. Provisions for the kill line should be made separately. The trip tank should be used for measuring displacement and recovery. 175.The BOP's should be checked prior to running in the hole and before tripping out. 176.On electric rigs, make sure the blowers are operating properly and that all electrical wiring is in good condition. 177.Water connections to exhausts are to be checked for proper spray. 178.Make sure all high-pressure swings are snubbed or anchored down. 179.All fire fighting equipment is to be inspected before starting the test. Fire fighting equipment should be positioned so that it can be used on the rig floor if necessary. 180.All personnel on location should be alerted that cigarettes and matches should be left in the accommodation area. 181.One person should be designated to make sure that the casing is kept full at all times while tripping out-of-hole and should also watch carefully for swabbing actions. The Driller would normally watch the trip tank. 182.Never remove kelly hose for the purpose of flowing through the kelly and goose neck. 183.DST's must not be conducted during storms when excessive static electricity may be present. 184.When turning drillpipe with tongs to open the DST tool, under no circumstances should more than one tong be used. If more power is needed, use a long-handled wrench. 185.Derrick Man should check his safety slide, line, and exit for operation and accessibility. 186.Check the test line for temperature decreases. A decrease in temperature often indicates downhole hydration, and consideration shall be given to stopping the test at

this time since a hydrate plug could form. If a hydrate or sulphur plug is suspected in drillpipe, exercise caution prior to disconnecting any of the pipeline: pull up to and close kelly cock before removing testing head. 187.If sour oil or gas is recovered, the drillpipe should be reversed out. 188.Regulate the valves on the surface manifold and attach the manifold to the last joint in the string while it is in the V-door or mousehole. 189.If it becomes necessary to do any work above the floor, a stabbing board should be erected. 190.The number of people on the floor during the test should be kept to a minimum. Only the Tester, the Driller, the Company Representative, and the Toolpusher should be on the floor. There is a tendency during a DST for spectators to accumulate in the doghouse and on the floor which results in congestion and confusion. This should be discouraged. It is not the test itself that is dangerous to personnel and equipment, but it is during the trip out of the hole following the test that the risk of fire and blow-out is the greatest. Personnel and supervisors tend to relax after the test tool has been opened and the contents of the formations being tested becomes known. It is at this time and during the trip out that caution should prevail, especially when gas and oil have been recovered. After the DST, run in hole with the drillstring to recondition hole and circulate out any gas that may have entered well bore. Hydrogen Sulphide Detection

All rigs must be equipped with a portable H2S Detector, such as a Drager or a Gastec testing kit which detects H2S concentrations that are harmful to personnel. The kit should be used for testing the gas drawn by the gas analyser when drilling into new gas zones. This is a simple test that detects H2S at low concentrations. It is recommended that this kit be used only as a means of detection, and if H2S is detected then a service company should be contracted to supply H2S safety equipment and expertise for personnel safety. The pH of the mud should also be carefully monitored if H2S is suspected. H2S will react with the mud and severely reduce pH. If H2S is present in the formation drilled, the drillpipe is likely to turn black as the H2S reacts with the steel. The most accurate determination of whether H2S is present in the formation is from a gas analysis of a sample from a DST. By using the H2S detector, monitoring the pH of the mud, and observing the drillpipe, a reasonable idea as to whether the formation contains any H2S should be obtained. If H2S is suspected, then the following precautions and procedures should be followed: Precautionary check list prior to testing in potential H2S environment: 191.Make sure that ALL personnel are aware of the dangers of H2S and USE the necessary protective equipment. All personnel should be instructed on the handling of H2S gas or liquid test results. 192.Ensure the following protective equipment is available and ready for use:

114.Gas masks. 115.Good supply of canisters and/or air cylinders. 116.H2S tester. 117.Resuscitator. 118.Adequate supply of aqua ammonia (ammonium hydroxide). 119.Adequate supply of H2S inhibitor (Corban). 120.Adequate ventilation. 121.Drillpipe racks which allow drainage of stands onto the floor. 193.The Company will hire a safety service company to supply the above equipment and expertise if H2S is suspected. 194.Obtain current information on the zone to be tested, if available, particularly with regard to H2S concentration, from the Operator's Representative or Drilling Department. 195.Flare booms and low pressure separator to be rigged in. 196.Water based drilling fluids must have a pH of at least 10.5. Mud density should give a minimum 14bar overbalance over expected formation pressure. 197.All surface equipment which could be exposed to H2S (to last valve on the floor manifold) must be pressure tested to ----- low and ----- high for 10 minutes prior to the test. Precautionary check-list for testing of a zone suspected of containing Hydrogen Sulphide: 198.Run two pump-out subs (drop bar activated type and pressure activated type). 199.Prevent the escape of fumes around working areas as much as possible. Provide adequate ventilation of the rig floor. 200.Use aqua ammonia to neutralise H2S gas detected in the drillstring. 201.Use inhibitor, Corban 302, to reduce drillstring damage from H2S gas. 202.Do not allow personnel to enter dangerous areas without first testing the concentration or wearing proper protective equipment. 203.Any person entering a dangerous area should be secured by a life-line held by another person outside the area. 204.Personnel should work in pairs. 205.Reverse circulate recovery. Bleed off procedure prior to releasing packer: Bleed off pressure through manifold to flare stack. If a fluid cushion was run and the well has produced the cushion without appreciable formation fluid entry, back pressure must be maintained at surface until the pipe is reverse circulated. Unseat packers. Wait 15 minutes for packer elements to relax. Pick up string above rotary table to where the stabbing valve can be shut in . Break off single and place in mouse hole. Slowly open stabbing valve and check for H2S or pressure. If H2S is encountered, see Ammonia treatment. Reverse circulating if H2S is encountered during the test:

NOTE: The test, including reverse circulation, can be conducted during darkness, provided the first gas reached the surface at daylight and there is adequate illumination. The drillstring must be reverse circulated prior to tripping. All sour tests will be reverse circulated through a test separator to a flare stack. Two pump-out subs will be utilised, each with different actuation methods. Depending on the type of test, fluids, and lighting conditions different procedures will have to be used. Always run a drop bar activated pump out sub one stand above the shut-in tool and a pressure activated pump-out sub one stand above that. Always run a kelly cock one joint below surface. Do not install the drop bar in the drop bar assembly at surface. Release packers. Wait 15 minutes before moving pipe. Pull to the kelly cock. Check the weight of the test string. The weight increase is indicative of the amount of fluid recovery. The drillpipe must be full of formation fluids or added drilling mud before reverse circulating. Hydrostatic pressures in the drillpipe and annulus should be as equal as possible to prevent serious "U" tube effect. Formation fluids in the drillpipe may have a lower specific gravity, causing the U tube effect when the pump-out sub is opened. The U tube effect can cause: 122.The hole to slough in, sticking the pipe. 123.The pump-out sub to plug off with shale. 124.Severe reduction of the hydrostatic head, allowing the well to blow. Install the open kelly cock, then close. Place the drop bar in the kelly cock and rig up the fail safe head, chicksans and floor manifold to the flare line. Shut the valves on the floor manifold. This slows the U tube effect by allowing the drillpipe to pressure up as the annular fluid is introduced. Open the valve to the kill line (close the valve on the standpipe) and pump across the flow nipple to ensure that all valves are open and the pumps are functioning. (Idle the pump). Open the kelly cock to drop the bar. Drop the bar to open the pump-out sub (POS). Watch for a change in drillpipe pressure and observe the annulus. When the fluid level drops immediately increase the pump rate and fill the annulus. Delay may cause the well to blow. When the annulus is full, shut down the pump, open a floor manifold valve, close the annular preventer and reverse circulate the fluid to the test separator. Catch samples of each formation fluid recovered through the bubble hose. Count pump strokes to determine approximate fluid recovery. Record the time required for each fluid in the drillpipe to reach the surface. Calculate the fluid level in the drillpipe using this times the pump output, and the displacement of the drillpipe. Fluid Level(m) =[Time(min.) x Pump Output( m3 /min)] Pipe Volume (m3/m) Monitor fluid return and note pumping time to changes in fluid-type (oil, mud, water, etc.) to calculate cubic metres of recovery of each fluid. Compare reduction in mud tank volume to the amount of fluid returning to the tank. This is the only way to determine if the mud is being pumped away down hole. Observe the annulus pressure and stay below the MACP. Continue circulating until all the recovery is in the separator. (Mud density at the chicksans is the same as that in suction.)

Remove surface equipment, install kelly, pump pill and pull out of hole using normal dry trip procedures. Watch for swabbing. The test tool can be pulled regardless of lighting conditions to the pump-out sub. Care must be taken in pulling the collars below the pump-out sub as they could contain hydrocarbons. If the ports plug and MACP is reached, shut off the pump, shut the kelly cock, and remove the top joint. Install the kelly, open the kelly cock and pump down the drillpipe to clear the ports. If the ports will not unplug, pressure up on the drillpipe until the pressure activated ports open. Stop pumping and rig up to continue reverse circulating. If the ports plug again, pull out using the test plugs and wet tripping procedures. Procedures for coming out of the hole when reverse circulation is not possible: NOTE: The procedure must take place during daylight. Use the following procedures for tripping pipe containing sour formation fluids: If H2S has been encountered during the test: The crew will complete the trip under mask using test plugs and mud can. 125.Use breathing apparatus when the test head is removed. 126.If aqua-ammonia is used, conduct tests to determine the presence of toxic and /or flammable gases. If present, mask-up all personnel until the tool is broken down and the area is determined safe. Add a mixture of aqua ammonia and water immediately after removing the test head. 127.Prior to applying the test plug on the stand, displace some fluid in the pipe with the dope brush. Pour approximately one cup of ammonia in the stand and when the fluid is drained out of the stand the ammonia works on any gas left in the pipe. Prior to breaking off the test head, check the area to ensure that there are no sources of ignition. For example, the derrick and doghouse lights are off. Inform personnel as to evacuation and shut-down procedures should the pipe unload its contents. If the pipe unloads, break out slowly, continuously monitoring joints for pressure release. If pressure is releasing, bleed off the pressure before continuing the break out. Have the mud can ready and properly directed to ensure proper disposal of contaminants. Caution all personnel about the dangers of positioning any part of the body over the open box area of the drillstem. Use test plugs if any oil or sour gases are contained in the drillstem. Before pulling every stand, test for toxic and/or flammable atmosphere. Rap every stand with a hammer to determine whether it is wet or dry. Wet stands require extra caution as they tend to be pressurised. When reverse circulation has been achieved, and if H2S is known or anticipated to be present, mask-up the crew for pulling the assembly below the pump-out sub. Purging Information Fires and explosions are avoided by eliminating air entrainment inside the equipment. The following guidelines can minimise the possibility of fires and explosions in enclosed vessels and the piping system:

Use clean tanks, particularly if a combustible purge gas is used. Tanks should be free from sulphide or pyrite build-ups. Tanks must have proper hatch seals and pre-set pressure thief hatches. Ensure that the thief hatch has a minimum 8oz. pressure rating and that the seal is in good condition. All system elements must be electrically bonded to each other, with the wellhead or ground rods as "ground". Where production tanks are vented to flare, the configuration must be: 128.Install a manual block valve on the vent line. The vent line to flare stack must be 31/2” minimum. 129.Install a pressure/vacuum device (pressure measurement tap and low pressure measurement device e.g., U tube manometer) on the tank or vent line before the block valve. 130.Use approved flame arrestors between the block valve and the flare stack. 131.A regulated or manually valved tank top blanket line. NOTE: It must be recognised that flame arrestors do not guarantee the prevention of flash-backs, and therefore the elimination of initial air and subsequent air entrainment is required. The purge medium should be manifolded to a control purging/measurement point, i.e., the test separator. All pilots, or open flame within 50m of the equipment to be purged must be extinguished. Purge with positive pressure sweet gas, propane or N2 before lighting the flare. The purge vapour should be measured. Liquid volume to vapour or mass to vapour conversions are allowed if the liquid volume or mass vaporised is measured accurately, and if it is ensured that all of the liquid is vaporised. Numerous measurement devices are available. The volume to be purged must be calculated prior to purging. For purge mediums heavier than air, purging should be a minimum of 1.5 times calculated volume , and purging should be from the bottom up. For purge mediums lighter than air, purging should be a minimum of 2.5 times the calculated volume, and purging should be from the top down. Top down purging is impractical in some situations. If bottom up purging is employed with purge mediums lighter than air, a minimum of 5 times calculated volume should be displaced. Small lines and vessels may be purged for a the number of minutes instead of rigorous calculations, if it is certain that the time chosen would exceed the overpurge guidelines. Measuring the purge gas flow rate with the separator meter run is recommended. Check residual oxygen with an explosion or oxygen monitoring device. The sensing should be performed at points other than the purge exit of the component (in case of air bypassing instead of displacement). Oxygen content must be such that the gas mixture is below its lower explosive limit. Following pre-start purging, a constant positive pressure shall be maintained on the tanks to avoid the introduction of air due to the flare stack Venturi effect or the loading of liquids from the tank. Vessels/tanks should be re-purged whenever air is accidentally or operationally introduced during the test.

Upon completion of a sour test, the tanks should be emptied and purged with sweet gas, propane, or N2. Purging the drillstring When dry drillpipe with air is opened to the formation, a cushion should be run in the string. If the well has enough energy, the cushion can be brought back to a rig tank. The returning cushion purges the drillstring. Extra precautions must be taken when air exists in the well string. 206.All non-essential personnel should be removed from the test area. 207.Manifolding should exist so that all vessels/tanks can be by-passed. 208.The well can initially be flowed through a by-pass directly to flare until the air is displaced from the drillpipe. Light the pilot and continue flow until well returns are apparent, allow gas to dissipate, shut down pilot and then proceed to purge the entire system of all air. Elements required for ignition: Fuel sources: 132.The well product. 133.The purge or blanketing vapour used. Oxygen sources (Air): 134.Air in the drillstring and testhead. 135.Air in surface equipment: 136.Air in vessels and lines 137.Air introduced after surface purging (this can happen when the well product pushes out the initial air 138.Air pulled into tanks through leaking or open hatches. Ignition sources: 139.Open flames 140.Static electricity 141.High-temperature 142.Debris in the closed system 143.Small, high velocity gas jets 144.Iron sulphides/polysulfides 145.Lightning. Procedure for use of aqua ammonia Aqua ammonia is effective in neutralising H2S gas. It will allow crews to pull the DST without the use of gas masks. All surface H2S vapours should be neutralised in drillpipe with 50-50 aqua-ammonia (after bleed off and prior to reverse circulation). If reverse circulating is not possible use aqua ammonia to pull the test. The aqua ammonia is not effective when liquid is encountered. Gas masks must be used. Ammonia is corrosive and toxic to the respiratory system. Ammonia should not be inhaled over extended periods of time. Harmful concentrations will always give warning by the sharp smell. Severe burns can be experienced if the fluid touches the skin or eyes. When mixing and using ammonia, the Safety Representative will be under mask and: 146.Wearing rubber gloves. 147.Rig floor clear of non-essential personnel or have personnel under mask 148.Wash down all spillage

When tripping pipe and H2S are encountered, clear the rig floor and do an ammonia treatment. Check every single for five stands, and every five stands thereafter for additional H2S readings. If H2S is encountered after the ammonia treatment this can indicate: 149.Fluid is near surface 150.Highly volatile fluids releasing H2S Prepare a mixture of 50 percent aqua ammonia (26 degrees Brume) and 50 percent water. Prepare 0.015m of mixture for each 12 strands to be pulled. (Adequate for up to 30 percent H2S.) Pour 0.0015m3 of mixture inside the drillpipe. Wash the drillstring, if necessary, to remove the offensive ammonia odour. Pull 12 stands of drillpipe (330m). Repeat steps 4 through 7 above until liquid is encountered in the drillstem. Reverse circulate the liquid out with a pump-out sub. When a pump-out sub cannot be used, crew members should wear gas masks and pull the test in the normal manner, disposing of the liquid recovery away from the rig. After a sour drillstring test and before running back in hole, the derrickman (equipped with breathing apparatus) should neutralise residual H2S in the stands of drillpipe, drained of liquid, by pouring 2.3 litres of the 50-50 ammonia solution into the stand from the top. Excess aqua ammonia can be easily washed off the floor and drillpipe with a water hose. When this procedure is followed properly, H2S is neutralised allowing the trip into the hole to be safely made without gas masks. Personnel must be on guard against pockets of H2S not neutralised.

CAUTION: There is a danger that personnel will become casual toward the hazard of H2S. Aqua ammonia reduces H2S danger, but certainly does not eliminate it. Corrosion Inhibition A corrosion inhibitor is designed to prevent hydrogen embrittlement occurring in the drillstring. It is imperative that the chemical is added prior to the drillstring coming into contact with the H2S gas/fluid. Inhibit water-based drilling fluids by maintaining a pH above 10. Inhibit VCMuds with the addition of commercially available scavengers. Use a filming amine inhibitor to protect the interior of the test string when running a sour drillstem test. Both water-soluble and oil-soluble inhibitors are available from safety service companies. If no water cushion is used, the inhibitor should be dumped down the test string. If a water cushion is used, mix the inhibitor with the cushion, and also put inhibitor on top of the cushion. NOTE: Ensure inhibitor is mixed in dope pails prior to making up tools and drillstring. Corrosion inhibitors of this type do not completely eliminate the effects of H2S corrosion. During and after exposure to H2S, reduce hook load as much as possible. Weathering in warm air helps to

reduce the amount of hydrogen in the steel and aids in preventing hydrogen stress cracks. Weathering for only a few hours on a warm day will reduce the incidence of hydrogen stress cracking.

NOTE: When H2S is suspected, notify testing company and ensure that their tools have been magnafluxed and all tools are designed for an H2S environment. Also ensure that they have been pressure tested to maximum rating. Method of use when water cushion is not used:

Run packer nearly to the bottom. Prepare a solution of water and Corban 302 by adding 0.0714 m of Corban to 1.0 m3 of water. Place 0.175m3 of this solution in the drillpipe for each 1 000 metres of drillpipe to be protected. Use minimum of 0.16m3 of solution. (e.g. For a 2 000 metre test, add 0.35m3, which would be a total of 0.025m3 of Corban and 0.325m3 of water.) Method of use when water cushion is used:

Add Corban 302 to water cushion at the rate of 0.005m3 of Corban for each cubic metre of water. To fill drillpipe: 151.0.045m3 of Corban for each 1 000 metres of 127.0mm drillpipe. Run the packer nearly to the bottom. Prepare a solution of 0.0714m3 of Corban 302 to 1.0m3 of water. Place one 0.0714m3 of this solution inside the drillpipe for each 1 000 metres of pipe above the water cushion. Proceed with the test in the normal manner. 209.Typical drillstem testing bottomhole assemblies Tool Sequence for Bottomhole Tests (From the Bottom):

Guide Shoe and Bull Nose. Tail pipe-heavy weight pipe or drill collars as required to withstand string weight and mud column weight. Tail pipe is not required when using "hook-wall" or inflatable packers. Perforated Anchor - run near the producing zone. Two Pressure Recorders - one inside and one outside. Two Packer(s) - two conventional packers or one inflatable packer. Safety Joint. One Inside Pressure Recorder. Hydraulic Jars. Hydraulic Main Valve. Mechanical Shut-In Tool. Three Drill Collars. One Joint of Drillpipe. Pump-Out Sub (POS) - always run one joint above collars.

Drillpipe to surface. A "kelly cock" - is run at the bottom of the first joint of drillpipe from surface. Must be sufficient inside diameter (ID) passage of bar to actuate POS. Fail-Safe Head - installed on top of drillpipe, with manually operated valve between the drillpipe and the remotely controlled valve. Bar Releasing Mechanism - installed above the head - bar to actuate the POS must be in place. Tool sequence for straddle tests (from the bottom):

Guide Shoe and Bull Nose. Tail Pipe - heavyweight drillpipe or collars as required to withstand string weight. Tailpipe is not required when using "hook-wall" or inflatable packers. One Outsider Recorder (not required on straddle test where by-pass plugging is not anticipated). Sub for By-pass Assembly. Bottom Packer(s) - two conventional packers or one inflatable packer. Perforated Anchor. Two Pressure Recorders - one inside and one outside. Top Packer(s) - two conventional packers or one inflatable packer. Sub for By-pass Assembly. Safety Joint. One Inside Pressure Recorder. Hydraulic Jars - jars should always be run. Hydraulic Main Valve. Mechanical Shut-In Tool. Three Drill Collars. One Joint of Drillpipe. Pump-Out Sub (POS) - always run one joint above collars. Drillpipe to Surface. A "kelly cock" - run at the bottom of the first joint of drillpipe from surface. Must have sufficient ID to allow passage of the bar to actuate the POS. Fail Safe Head - installed on top of drillpipe, with a manually operated valve immediately underneath. Bar Releasing Mechanism - above fail safe head with bar in place. 210.Calculating water cushion requirements Background Information for calculation:

211.Packer depth: 4 800 metres. 212.Mud Weight: 1.32S.G.

213.Desired Differential Limit across packer - 28.0MPa. 214.Drillpipe 127.0mm, 29.0kg/m Grade E collapse - 69.0MPa (100 percent rating). 215.Cushion - Fresh water (gradient 9.79kpa/m). Calculation water cushion requirement:

216.Hydrostatic Head - 4 800 a 0.00098 x 62.1MPa. 217.Water Cushion Required to Limit Differential Across Packer to 28.0MPa. 218.Hydrostatic of Water Cushion Required = 62.1 - 28.0 = 34.1MPa = 34 100kPa. 219.Height of Water Cushion = 34 100 = 3 483 metres 9.79. 220.Water Cushion Required to Prevent Drillpipe from Collapsing. 221.Drillpipe Collapse 69.0 MPa 100%. 55.2 MPa 80%. Use 80 percent for safety. 222.Then Water Cushion Hydrostatic Required: 62.1 - 55.2 = 6.9MPa = 6 900kPa 223.Height of Water Cushion = 6 900 = 705 metres. 224.Since the limit is 28.0 MPa of packer differential, run 3 483 metres of water cushion. To prevent drillpipe collapse, either flow back 2 778 metres of water cushion and shut in well; or maintain a backpressure on wellhead of 6.9MPa or higher during the test. This example may be an abnormal case, but it illustrates the importance of water cushion requirements from the packer differential and the drillpipe collapse point of view. Several conditions can change the above assumed limitations. These are: 152.Testing in a "rat hole" can increase packer differential limitation due to smaller hole size. 153.Use of drillpipe of higher grades can increase collapse limit. 154.Prior knowledge of formation productivity may allow a reduction in water cushion. 225.Laboratory analysis of gas, oil and water samples A standard analysis is to be run on all samples obtained from every DST. Where several samples are taken during the test, the standard analysis will be done on the most representative samples. The Company Representative will issue a Field Service Order for the analysis of all DST samples. Where special analysis work is required (if known in advance of drilling the well), the type of analysis will be indicated on the Well Prognosis. When samples are sent to the laboratory for analysis, the following information should be included on the label/tag:

226.Complete well name and location. 227.Date and time of sampling. 228.Name of person and company who obtained sample. 229.Location of sample, i.e. surface, top, middle, bottom of drillstring, etc. 230.Specific data such as temperature, DST number, pressure, etc., relating to sample, if applicable.

231.Name of Company Representative to be contacted. 232.Attach the Field Service Order with the sample when it is sent to the laboratory. On the Field Service Order, instruct the laboratory to call the appropriate person in the Coparex Office. 233.Guidelines for multiple tests More than one test should be run on one trip in the hole only if the following conditions are satisfied:

234.On the preceding test, the blow was weak and decreasing or dead throughout the test. This indicates very little recovery or that there was gas to surface at a rate to 50 000 m3/d or more with no oil or water spray. (This does not include mud slugs or spray which are inevitable.) 235.Where low-pressured, easily damaged zones are present, there should not be any tests on the way out from a deeper test, as the recovery from these zones could be suppressed by even a small amount of liquid recovered from the deeper tests.

Form 5.1 Well logging program

Form 5.2 Log quality control check list

Form 5.3 Service company performance evaluation

Form 5.4 Field data transmittal form Contents

8. FISHING ........................................................................................................................xlviii 8.1 Introduction .............................................................................................................xlviii 8.2 Common Causes of Fishing....................................................................................xlviii 8.3 Freeing Stuck Pipe........................................................................................................l 8.3.1 Free-Point ............................................................................................................l 8.3.2 Wireline free-point determination ........................................................................ li 8.3.3 Back-off procedure.............................................................................................. li 8.3.4 Jarring ................................................................................................................ lii 8.3.5 Stuck in squeezing salt ..................................................................................... liii 8.3.6 Differentially stuck pipe ..................................................................................... liii 8.3.7 Stuck logging cable or logging tool ................................................................... liii 8.4 Fishing Tools.............................................................................................................. liv 8.4.1 Overshots.......................................................................................................... liv 8.4.2 Spears............................................................................................................... liv 8.4.3 Junk baskets and subs....................................................................................... lv 8.4.4 Magnets ............................................................................................................. lv 8.4.5 Bumper subs ...................................................................................................... lv 8.4.6 Jars .................................................................................................................... lv 8.4.7 Milling tools ....................................................................................................... lvi 8.4.8 Extension subs.................................................................................................. lvi Illustrations

Figure 8.1 Keyseat sticking.......................................................................................................l

236.FISHING

237.Introduction Fishing is any operation to release, remove, or recover a fish or junk that has fallen to the bottom of a well or is stuck in the well. One of the most common fishing tasks occurs when the drillstring is twisted into two parts. After a twist-off occurs, always circulate the hole clean and condition the mud before tripping out. The following actions should be taken to reduce the chances of becoming stuck prior to drilling into high-pressure zones or weighting up:

238.Stabilisers should be added to reduce wall contact. 239.Consideration should be given to substituting drill collars with HWDP as much as possible. 240.Consideration should be given to running the drilling jars between drill collars and HWDP. By carefully measuring the pipe removed from the hole, the operator can determine the depth at which he may engage the fish. By examining the end piece brought from the hole, the operator can determine the characteristics of the fishing neck to be engaged. The size of hole being drilled will dictate the type of fishing tools to be run. If there is sufficient clearance, a tool that will engage the fish externally is preferable. The minimum size overshot should be run to allow subsequent washover operations (if required). If there is not sufficient clearance, an internal catching tool should be run. It is good practice to calliper the drillstring nearest to the fish to be sure whether or not the pipe or drill collars have been worn to a smaller size than their original outside diameter.

NOTE: The most important information of any fishing job is to know exactly what the fish consists of and to know exactly where the top of the fish is. Make a sketch of each BHA prior to running in the hole. It is very important to check OD's and ID's in the pin and boxes of every piece of the BHA. The ID, OD, and fishing neck should be recorded. Mandrel specifications on jars and shock subs should also be recorded. Have accurate count and measurement of all pipe, collars and subs on the installation.

241.Common Causes of Fishing 242.Twist-off A twist-off results from fatigue of the drillstring. Fatigue is caused by damage due to rough handling, scarring from tong dies, incorrect heat treatment, and slip wear. The constant axial loads and torque transmitted to the drillstring causes damaged tool joints and eventual failure. This fatigue opens a traverse crack in the pipe, enlarging to a point of failure. This sometimes appears as a long tear, however, this is helpful because the tear is a mirror image of the top of the fish.

243.Drill bit disintegration 244.Differential sticking Penetration of low-pressure, highly porous and permeable formations presents conditions for possible differential sticking. When hydrostatic pressure is greater than that of the formation, seepage into the formation may cause a thick mudcake to be formed. This

differential tends to push the pipe or collars against the formation, thus sticking the pipe. The possibility of differential sticking is increased by the use of oversized collars. Sticking forces generated by differential sticking can be great. Such forces are the main reason that jarring or working the drillstring is often unsuccessful when differential sticking occurs. Differential sticking is evidenced by different conditions than most other forms of pipe sticking. Differential sticking is usually characterised by no movement of the pipe whatsoever and by free circulation (no pack-off). If the pipe cannot be worked free without exceeding tension limits then the hydrostatic pressure at the stuck point must be reduced or the filter cake must be reduced and softened. Mud characteristics affecting differential sticking: 155.Coefficient of friction of the filter cake. 156.Area of contact of the drillstring and the cake. 157.Pore pressure and compaction of the filter cake. 158.Solids content. 159.Overbalance of the mud column. Prevention of differential sticking: 160.Keep the drillstring in motion either by reciprocation or by rotation to keep a lubricating mud film between the filter cake and the drillstring. 161.Avoid excessive deviation that may increase the contact area. 162.Keep the mud density as low as possible, consistent with well safety. 163.Maintain minimum filter cake thickness. 164.Reduce the solids content of the mud. 165.Add lubricants that would reduce the coefficient of friction of the filter cake. 245.Mechanical sticking Stuck pipe can result from improper hole cleaning and the settling of drilled cuttings packing off around the drillstring. This can be caused by insufficient pump pressure, and/or low viscosity’s. The drillstring is held in place and cannot be freely moved. Free movement down is occasionally possible without free movement upwards. Sticking due to solids accumulation (annular pack-off) is also commonly preceded by increased drag or torque, and by erratic increases in circulating pressure. Mechanical sticking can result from penetrating the formation faster than it is possible to circulate out cuttings. Keyseat sticking is also a form of mechanical sticking, see Figure 8.1. 246.Tools or other objects dropped down the hole This usually occurs when the string is out of the hole and repair work is taking place. This type of fish can range from a screwdriver to a pipe wrench. Bits that have been run too long may lose cones in the hole and require a special trip using a downhole magnet to recover loose iron.

Figure 236.1 Keyseat sticking

247.Wireline breakage Wireline cable logging, perforating, and surveying may sometimes break. This is often the result of trying to pull a stuck tool free, or running out of the hole too fast and "hanging" up. The cable below the break will fall and pile up.

248.Freeing Stuck Pipe 249.Free-Point NOTE: Wireline free-point should be run before attempting to back-off. Stretch readings are necessary to:

250.Determine stuck point. 251.Determine the size of string shot to run. 252.Determine the weights and torque needed to properly find a free-point. The following is the field method to estimate the free-point (stretch pipe-field estimate).

Note the weight of the string, including blocks (TSW). Pick the pipe up to this weight (mark pipe at rotary). Pull additional 10 000 - 15 000daN and mark the pipe at the rotary table. (Do not exceed the allowable tension limits). Measure the distance from the original mark. Repeat the procedure. L

=

2.6355 (e x W) Pull over string weight, (1 000daN)

where: L = Length of free drillpipe, m e = Average elongation or stretch, mm W = Weight of drillpipe, kg/m Pull over string weight, 1 000daN

166.Ensure that the true weight down to the stuck point has been picked up and is in tension (none of the pipe down to the stuck point is in compression). 167.The pipe should return to its original position when the tension is removed. The Stretch Technique should not cause permanent elongation of the pipe. 253.Wireline free-point determination The free-point indicator is a very sensitive and accurate electronic instrument which measures both stretch and torque movement in a string of stuck pipe, and transmits this information through the conductor cable to the surface. It can accurately locate the lowest point from which a string of pipe can be successfully recovered. The free-point indicator can be run in either drillpipe, tubing or casing and can be used simultaneously with the string shot. This allows the drillstring to be backed off in a single run.

The results of the free-point indicator are presented as "a percentage of free pipe" versus depth; for easier interpretation. Readings above 85% "free" in both stretch and torque are good indications of free pipe. Back-off should not be attempted if the "percentage of free pipe" signal for tension and stretch equals 85% or less. Before running the free-point indicator, the following precautions must be taken:

254.Determine the maximum applicable overpull and torque to the string. Pay special attention to tapered strings. 255.In order to be able to use the top drive as a "lubricator" during the running of wireline tools, make up one joint of drillpipe and a kelly cock below the top drive. This will allow pulling the logging tools above the kelly cock and closing in the well if necessary. 256.When not using the kelly or the top drive, always install a kelly cock on the string in case a reservoir has been penetrated. Also, install a wireline circulating head on the string. 257.Back-off procedure A string shot consists of an explosive detonating cord that produces a vibratory shockwave to loosen or unscrew a predetermined thread. Left-hand torque is applied with neutral weight applied at the back-off point. For the proper sizing of the shot certain factors should be known:

258.Pipe size and weight. 259.Depth of stuck pipe. 260.Mud or fluid weight. 261.Temperature of the well. Back-off operations are potentially dangerous:

262.Ensure radio silence procedures are in force prior to arming the back-off tool and until the tool is 100m below the seabed. After back-off has been completed upon pulling out of the hole, radio silence must also be in force from the time the tool is 100m below the seabed until the time the tool is known to have fired completely (inspected visually at the surface), or is disarmed in case of a misfire. 263.Only necessary and experienced personnel should be on the drill floor. 264.Tong and slips must be in good repair. 265.If any reservoir has been penetrated then a wireline circulating head must be installed on the drillstring. 266.The slip handles must be tied with soft line when applying torque with the slips. 267.When applying torque, the elevator shall be latched around the pipe and free below the tool joint. 268.The hook shall be unlocked when the pipe is being rotated with slips. 269.Back-up lines must be a minimum 7/8" in size. Double back-up lines may be necessary. 270.If the pipe is to be lifted out of the slips without the tongs engaged and biting, ensure that there is no residual torque present to rotate the pipe. Back-off point The string shot strength should be sufficient to back-off the pipe without causing major damage to the pipe or the connection. The size of the shot depends on the back-off and whether the back-off is in the drillpipe or drill collars:

The drillstring should be backed off one or two joints above the stuck point. Jars are more effective if positioned close to the stuck point. Attempt to back-off in straight or gauge hole sections if possible. Drillstring parted near a casing shoe should be backed-off in the casing or below a washed out section. 271.Jarring Prior to jarring always mark the string position at the rotary table. The proper jarring method is to allow the jar to trip with the required overpull before further overpull is applied. Heavy pulling and jarring shall be carried out using the kelly or top drive. Where this is not possible, the elevator latch shall be secured by means of a rope or chain. If possible, the kelly spinner, elevator and bales should be removed. Avoid jarring with an overshot if possible. It is preferred to screw back onto the fish with a jarring assembly. A safety joint may be incorporated. During jarring procedures all personnel must be cleared from around the drill floor. When the string is free pull it up several meters and commence circulating slowly.

When jarring for an extended period, the drill line, derrick and travelling equipment, should be visually inspected at regular intervals.

272.Stuck in squeezing salt Jarring operations should commence immediately in an effort to free the pipe. If jarring alone will not free the drillstring, another option is to consider circulating 5m3-10m3 fresh water pills. Some precautions for its use are:

273.Hole stability (water sensitive formations). 274.Well control (reduction in hydrostatic pressure will not create a kick situation). 275.Differentially stuck pipe 276.As soon as differential sticking is suspected the first attempt to free the pipe is jarring. Another technique often used to free differentially stuck pipe is to reduce the mud weight in steps. This is only allowed if well control is not a factor. 277.If jarring does not free the string, and reducing the mud weight is not feasible or not effective, consider spotting a pill. The type of pill is dependent on the formation and the mud type in use. Approved fluids for stuck pipe should be spotted to cover all of the bottomhole assembly and have enough left in the pipe to move 0.15m3 an hour for 48 hours. This will keep the bit open, prevent the setting of solids, and expose the formation to new oil and surfactants. After 24 hours of soaking, a free-point should be run. If only the collars are stuck, consideration should be given to back-off and going in with jars and a fishing string. If the drillpipe is stuck a washover pipe should be used. 278.Another method is the Drillstem Test Tool to alleviate hydrostatic pressure. Some precautions for its use are necessary: 168.The hole should be in gauge. 169.There is danger of sloughing when the tool is open. 170.Take precaution for any high-pressure zones below the packer seat. 279.Nitrogen spotting to free differentially stuck pipe can be used. The purpose of this procedure is to lower the hydrostatic pressure by lowering the fluid in the hole. Displace the drillstring to N2. The N2 is then is bled off and the annular fluid level will fall. Care should be taken to ensure that the reduction in hydrostatic pressure does not create a kick. This method will not work with a float in the drillstring. 280.Stuck logging cable or logging tool If a logging tool is stuck, no attempt is to be made to break the cable at the weak point unless instructed by the Company Representative. The Company Representative is responsible for ensuring that the logging companies/contractors have a complete set of fishing equipment on site. The two methods of recovering logging tools are:

281.Cut and thread (strip-over) method. 171.The logging cable is key-seated. 172.Radio active sources are involved 173.The fish is stuck off-bottom.

282.Side-door method. 174.The tool is stuck close to the surface. NOTE: Stuck logging tools with radioactive sources must be fished using the strip over/reverse strip technique. The weak point must not be broken.

WARNING: If a radioactive source becomes stuck, it must be treated as an incident, refer to the Company Health, Safety and Environmental Management System. All attempts must be made to recover the source. If the source cannot be covered it must be covered by 30-10 m of cement..

283.Fishing Tools 284.Overshots The most effective fishing tool to engage the fish externally is the Bowen Overshot. It can be used with a rubber packer moulded lip. When the overshot is lowered over a fish, the lip will seal completely around the fish and the fluid will be directed through the fish. Circulation under pressure up and around the outside of a stuck fish is a very important factor in loosening it. Right-hand rotation is normally used to engage the fish, thus preventing back-off of the string at an undesirable connection. If the fish is plugged, or a potential well control problem exists, do not run a packoff. Instead run a circulating sub just above the overshot. It should be the type of circulating sub that requires a ball dropped from the surface. Run as small a guide as the hole conditions will permit. The fishing bumper sub should be installed in fishing strings immediately above the fishing tool or safety joint. It assures the operator of the ability to release the fishing tool when it becomes impossible to pull the fish.

285.Spears Spears are used when not enough outside clearance is available to run an overshot. It can usually be released if the bumper sub is run above the spear. Always consider running a stop ring with a spear. Washover spears Hole conditions should be taken into consideration before running these tools. The advantage of using washover spears is that the washover operation and the retrieval of the fish can be done on one run. A back-off shot can be run and the portion that is washed over can be backed-off and retrieved. This helps prevent the fish from resticking while making a trip for an overshot, and helps to prevent the fish that are stuck off bottom from falling. The disadvantage is the risk of backing-off the wash pipe during the back-off operation. The movement of the wash pipe may be restricted and problems will arise to release the spear if the back-off is unsuccessful. The length of the drill collars in the stuck string is a limiting factor when the weight of the fish is transferred to the wash pipe and may part the wash pipe.

Washover pipe

For washover operations it is advisable to run the minimum size wash pipe that will cover the fish and will give room for circulation. In soft formations 12mm is recommended, while six mm may be used in hard rock formations. The length of the wash pipe depends on the hole conditions. Approximately 90m is a rule of thumb in a good hole. Keep the wash pipe moving at all times because it gets differentially stuck very easily. Wash pipe joints are weak and therefore should be monitored for any torque build-up. Do not leave the rig controls unattended and monitor torque and pressure build-up; this may indicate that the washover shoe is worn out. Continuing to drill with a worn out shoe may cause the wash pipe to back off. Washing over When washing over it is recommended that oil jars should be run with enough drill collars above them to allow the jars to be effective. A safety joint should be used on top of the wash pipe. The wash pipe with a drill collar spear should be considered when washing over collars or tools which are stuck off bottom. Washover shoes When using washover shoes short tooth mills are recommended for medium to hard formations. Flat bottom shoes are used for cutting over reamers, stabilisers, tool joints, etc. They will not cut through the formation very fast. Check the previous shoe to help in selecting the next shoe.

286.Junk baskets and subs A junk sub directly above the bit is a good method for recovering small pieces of junk. When iron is suspected a basket should be run prior to diamond bit drilling or coring. The reverse flow pattern in the reverse circulation basket is caused by jet nozzles. The basket may fill up with loose shale and boulders. Coring type junk catchers are used for recovering any type of junk that can be cored over. Formations must be soft enough to allow for coring and breaking off the core. Reverse circulation baskets: Jet nozzles create a reverse flow pattern.

287.Magnets Fishing magnets, when run on tubing or drillpipe, are good for recovering cones and small junk. Magnets run on wirelines are not recommended for use in an open hole. Ensure the magnet is fully charged before running it.

288.Bumper subs Bumper subs are run in fishing strings along with jars. They can be run above or below the jars, although it is preferable to run them below. A bumper sub provides free travel to jar loose the slips of a spear or overshot. It can also bump down on a fish. Two bumper subs are sometimes run in deep or deviated holes to provide necessary travel which can then be observed at the surface.

289.Jars Jars are designed to impact a sudden upward or downward blow on the tools below it. When jarring, always run enough drill collars above the jars to make the jars effective. Jars should never be used below tools with a greater diameter than that of the jar; if the tools above the jar become stuck, the jar is useless. When fishing jars are run with fishing tools it is recommended to place drill collars on top of the jars instead of heavyweight drillpipe. This will yield a more effective blow when bumping down.

If the jar is to be used in tension, an additional 15-20% of the desired weight on the bottom should be below the jar. If the jar is to be used in compression, 15-20% of the desired weight on the bottom should be above the jar. Jar intensifiers Jar intensifiers are accessories to intensify the jarring impact force. They are run to utilise all the energy that is stored in the stretched drillpipe, resulting in greatly increased jar force. It is recommended to install intensifiers immediately above the drill collars. Surface jars Surface jars are designed to deliver a heavy downward blow against a stuck fish. They perform ideally where key seating is the problem. A surface jar has a 48" stroke. They also could be used to disengage a fish. The effective depth is usually limited to less than 1000 m.

290.Milling tools Types of milling tools are:

291.Pilot mills These are used for milling up tubular equipment. The nose holds the mill straight and the upper body does the milling. The pilot should be near the TD of the fish. Over- milling will cause cuttings to ball up around the tools. Therefore, pick the mill up frequently and pump out the hole. 292.Tapered mills These are used for milling inside casing, dressing a liner, and cutting out burrs. A tapered mill should not be run in collapsed casing except as a last resort. 293.Section mills Are for cutting out sections of casing. The casing should be cemented and the casing centralisers will determine the milling operations. 294.Inside fluted mills These are used to dress off the top of the pipe or the fish to the desired size. 295.Concave mills These are used to dress off the top of the fish when a torn or ragged neck is present. 296.Mill guides These are used in the bottom of an overshot to dress off the top of a fish and enable the grapple to slip over. Run a mill guide when available. Any mill run inside a casing should be well stabilised and not have any hard facing on the side. Carefully select the type of mill to prevent them from walking. Use extreme caution when milling inside the casing to prevent cutting through it. Removing cuttings is essential. When water is used milling is difficult; therefore reverse circulate if possible. Running a junk sub when milling and putting a magnet at the end of the flowline will help remove fine metal cuttings. After finishing milling operations the BOP stack and wellhead should be cleaned from steel cuttings/shavings. Install magnets in the flowline to collect steel cuttings out of the mud. Steel cuttings left in the BOP cavities can create damage to packers, wellhead seal assemblies, etc., if they fall into the wellbore after operation.

297.Extension subs The upper end of the fish can be split or distorted. In this situation an extension should be run so it can be lowered far enough to allow the grapple to engage with an undamaged section of the fish.

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9. DIRECTIONAL DRILLING....................................................................................................i 9.1 General .........................................................................................................................i 9.1.1 Definitions ............................................................................................................i 9.2 Conventional Directional Drilling .................................................................................. ii 9.2.1 Kicking off............................................................................................................ ii 9.2.2 Angle building..................................................................................................... iii 9.2.3 Angle holding ..................................................................................................... iii 9.2.4 Angle dropping ................................................................................................... iii 9.2.5 Factors which affect the directional behaviour of rotary assemblies in directional rotary assemblies .................................................................................................. iii 9.2.6 Dogleg and dogleg severity.................................................................................v 9.2.7 Directional control with rotary assemblies...........................................................v 9.2.8 Non-magnetic Drill Collars ................................................................................ vii 9.2.9 Short drill collars, extension subs...................................................................... vii 9.2.10 Bottomhole assemblies with responses under ideal conditions ..................... viii 9.2.11 Selection of stabiliser type ............................................................................. viii 9.2.12 Types of directional patterns ............................................................................ ix 9.2.13 Kick-off point and build-up rate .........................................................................x 9.2.14 Factors affecting trajectory control of rotary assemblies.................................. xi 9.2.15 Deviation control on vertical holes ................................................................... xi 9.2.16 Kicking off........................................................................................................ xii 9.2.17 Using the mud motor for drilling and trajectory change................................... xii 9.2.18 Adjustable bent housing................................................................................. xiv 9.2.19 Reaming.......................................................................................................... xv 9.2.20 Fatigue in directional drilling............................................................................ xv 9.2.21 Fishing in directional drilling ............................................................................ xv 9.2.22 Tool face orientation........................................................................................ xv 9.3 Horizontal Drilling ..................................................................................................... xvii

9.3.1 Horizontal drilling pattern ................................................................................ xvii 9.3.2 BHA weight and weight on bit ......................................................................... xvii 9.4 Survey Equipment and Procedures ......................................................................... xvii 9.4.1 Drift surveys ....................................................................................................xviii 9.4.2 Magnetic surveys ............................................................................................xviii 9.4.3 Magnetic single-shot surveys - unloading, developing and reading the film xx 9.4.4 Azimuth reference systems ............................................................................. xxii 9.4.5 Gyroscopic surveys ......................................................................................... xxv 9.4.6 Measurement while drilling (MWD) ................................................................. xxv 9.4.7 Directional survey calculations....................................................................... xxvi 9.4.8 Magnetic declination correction......................................................................xxvii 9.4.9 Magnetic interference and instrument spacing .............................................xxviii 9.4.10 Surveying inaccuracy .................................................................................... xxx 9.5 Recommended Bottomhole Assemblies ............................................................ xxx 9.5.1 General ........................................................................................................... xxx 9.5.2 Drill collar size election.................................................................................... xxx 9.5.3 String weights................................................................................................. xxxi 9.5.4 Problem Holes................................................................................................ xxxi 9.5.5 Deviated hole ................................................................................................. xxxi 9.5.6 Key Seating.................................................................................................... xxxi 9.5.7 Float subs....................................................................................................... xxxi 9.5.8 Static method .................................................................................................xxxii 9.5.9 Dynamic method ............................................................................................xxxii 9.5.10 Circulating Subs ...........................................................................................xxxii 9.5.11 Vibration control (shock subs)......................................................................xxxii 9.5.12 Drilling Jars ..................................................................................................xxxii 9.5.13 Drillpipe strainers...........................................................................................xxxii 9.5.14 Straight hole BHA's .....................................................................................xxxiii 9.5.15 Stiff (packed hole) assembly .......................................................................xxxiii 9.5.16 Kick-off and deviation assemblies...............................................................xxxiv 9.5.17 Bottomhole assemblies tangent assemblies (Navri-drill System/DTU) .......xxxiv 9.5.18 Angle-build rotary assembly........................................................................ xxxv 9.5.19 Tangent rotary assembly.............................................................................xxxvi 9.5.20 Check trips assemblies ...............................................................................xxxvi 9.5.21 Check trip assemblies for after DTU runs ..................................................xxxvii 9.5.22 Accelerator position................................................................................... xxxviii 9.6 Sidetracking ......................................................................................................... xxxviii 9.6.1 Reasons for Sidetracking in open hole ....................................................... xxxviii 9.6.2 Sidetracking procedures in open hole...........................................................xxxix Illustrations

Figure 9.1 Fulcrum principle ................................................................................................... vi Figure 9.2 Pendulum principle ............................................................................................... vii Figure 9.3 Bottomhole assemblies with responses under ideal conditions (no hole curvature)viii Figure 9.4 Directional drilling terminology............................................................................... ix Figure 9.5 Build and hold pattern.............................................................................................x Figure 9.6 S type well pattern ..................................................................................................x Figure 9.7 Moineau motor configuration ............................................................................... xiii Figure 9.8 High side of the wellbore ..................................................................................... xvi

Figure 9.9 Horizontal drilling pattern .................................................................................... xvii Figure 9.10 Angle unit............................................................................................................ xx Figure 9.11 Single shot instrument ....................................................................................... xxi Figure 9.12 Degree angle unit (0-10 degree)....................................................................... xxii Figure 9.13 Degree angle unit (0-90 degree)....................................................................... xxii Figure 9.14 Azimuth.............................................................................................................xxiii Figure 9.15 Quadrant bearings ........................................................................................... xxiv Figure 9.16 Azimuth-quadrant conversion .......................................................................... xxiv Figure 9.17 Magnetic declination correction .......................................................................xxvii Figure 9.18 East magnetic declination correction ..............................................................xxviii Figure 9.19 Source of magnetic interference...................................................................... xxix Figure 9.20 Magnetic interference and instrument spacing ................................................. xxx

298.DIRECTIONAL DRILLING

299.General The following deals with drilling wells which are substantially deviated from vertical. These situations will normally arise because of:

300.Strong deviation tendencies in the area (i.e., severely dipped formations) or, 301.Surface problems which will not allow rig placement directly above the bottom hole target. The former case involves controlling natural deviation tendencies by the use of various bottom hole assemblies in order to hit the desired target area. The latter case involves planning a well bore trajectory which is intentionally "kicked off" from the vertical, taking the smoothest possible path to the target. The following provides only general comments on directional drilling. Well specific, and more detailed information will be given in the directional drilling programme. Directional drilling operations in the North Sea will be performed by a qualified directional drilling contractor. The contractor will supply the specific plot for the well. Normally the contractor will also deliver the directional drilling tools as part of the package.

302.Definitions Average Angle: The average between drift angles taken from any two consecutive survey points. Azimuth: The azimuth of a borehole at a point is the direction of the borehole on the horizontal plane, measured as a clockwise angle ( 0 to 360 degrees). BHO Sub: Bottom hole orienting sub - any sub designated to force the survey instrument into a predetermined relationship with the Bottom Hole Assembly. Example: Mule Shoe Orienting sub. Course Deviation: Distance horizontally between the surface location and target location, along a straight line in a specified direction. Directional Drilling: The science of directing a wellbore along a predetermined trajectory to intersect a subsurface target. Direction of Closure: The direction or azimuth of a line drawn from the surface location to the downhole target or survey station. Drift Angle or Inclination: The angle of the wellbore in relation to vertical. Dogleg Severity: A measure of the amount of change in inclination and/or direction of a wellbore, expressed in 30 degrees/metre. Kick-off Point: Depth at which wellbore deviation from vertical is initiated. Intentionally deflected wells: Those that increase the hole angle by one of several means in order to reach a subsurface target that could not be intersected through natural deviation. Measured Depth: The actual length of the borehole from the ORT (pipe tally depth) to any specified station.

Mule Shoe: A cam in the shape of a mule shoe which converts downward motion to rotation and downward motion. It is used to align a single shot survey tool to the high side of a mud motor. Mule Shoe Orienting Sub: A sub bored out to accept a mule shoe sleeve. Mule Shoe Method of Orientation: A means of orienting tools, after they have been run into the hole in any random direction. In this method, a Mule Shoe Assembly is attached to the protective barrel of a survey instrument in such a way that a known relationship exists between the mule shoe slot and a scribe line on the survey record. When the instrument is lowered into the drill string, the key of the mule shoe sub forces the mule shoe assembly to rotate until the mule shoe slot locks on the key. The key has a known relationship to the BHA allowing the survey instrument to record its orientation. Naturally Deviated Wells: Those which build angle due to the presence of dipped formation bedding planes. The approximate hole angle versus depth that is expected from the formation dip can be used to determine the expected distance that the well bore will terminate laterally from the wellbore at surface. This distance is known as the horizontal displacement. If the direction of natural deviation is known, the surface location for the rig can then be selected in the opposite direction at a distance roughly equivalent to the anticipated horizontal displacement. Normal drift direction is updip to bedding planes. Station: Any point at which a survey is run. Subsurface targets: The target is specified by the geologist, who will define a certain point as the target and also specify the acceptable tolerance having the target as its centre. Subsurface targets may be circular, rectangular or virtually any other shape. Target Location: A predetermined position at a specified distance and direction from the surface location. Telltale: A lead plug held in the upper end of the mule shoe slot. When the mule shoe seats over the key, the telltale is mashed by the key. Tool Face: The direction the drillstem will face is the tool face direction. The orientation of the high side of the motor. Always measured in degrees to the left or to the right of high side of the bent housing on the motor. Tool Face Orientation: The rotational position of a downhole motor relative to the high side. Vertical Depth: The difference in vertical depth between two Stations. Vertical Section: The distance on the horizontal plane from one station to the next station.

303.Conventional Directional Drilling 304.Kicking off Getting "kicked off" from vertical can be achieved in a number of ways but is most efficiently done with the use of a mud motor and a bent sub or motor with a bent housing. Adjustable bent housings are most efficient because they can be readily changed from 0° to 2° in 1/4° increments. Choices of positive displacement type mud motors will vary from low speed/high torque types to high speed/low torque types. The exact type of motor used should be chosen while programming, considering the type of formation to be drilled and motor performance history in the area. Turbines have very limited application as they are very high speed and must be used with diamond bits.

At the beginning of the kick-off the motor/bent sub combination can be used to build the desired inclination and azimuth. Very often, left hand lead must be built into the starting azimuth to compensate for right hand bit walk expected later while rotary drilling. The desired starting azimuth should be achieved as soon after kick off as possible. Simultaneous change of azimuth and inclination should be minimised. This can lead to severe doglegs.

305.Angle building It is very often most efficient to continue drilling after kick-off with the motor/bent sub combination until the bit must be pulled. This point may be in the build section, the hold section, or possibly TD in the case of very shallow wells. Economics may, however, dictate that a conventional rotary assembly be used to complete the angle building portion of the hole. In either case angle building should not be planned in excess of 3°/30 meters. Doglegs should not exceed 5°/30 meters in shallow wells (less than 1500 m) or as specified in the programme on deeper wells.

306.Angle holding Angle holding is usually more difficult than changing angle. Most assemblies will have a tendency to either build or drop angle. The purpose of holding angle is to minimise the curvature effects and spread them over as long an interval as possible. If a desirable trajectory has been achieved, change drilling parameters as little as possible. Weight changes are most significant in the directional tendency of a particular bottom hole assembly. If weight changes must be made, make them slowly. Abrupt weight changes can cause severe doglegs. The following applies for the range of directionally drilled wells; not all apply to a given well. Problem

Solution

Insufficient Bit Walk Too Much Bit Walk Insufficient Angle Build Insufficient Angle Build

Increase WOB/Decrease RPM Decrease WOB/Increase RPM Increase WOB Decrease WOB/Increase RPM

Bits should not be run to a very dull condition as this may increase dogleg tendencies. Bits chosen for angle holding should not have a high degree of offset. Bits with high offset may increase bit walk or deviation tendencies. PDC bits are recommended. It is very important when trying to hold angle or controlling deviation, not to overreact. Apply only minimum changes necessary to correct a problem, but react in time and check the actual performance on the plot immediately.

307.Angle dropping Angle dropping can also be achieved by means of conventional rotary assemblies using stabiliser placement. This is generally achieved by the pendulum effect of the drill collars below one or more stabilisers. Dropping angle is usually more easily achieved when drilling at high inclination angles than when the inclination is low. Attempts should not be made to drop angle at rates faster than 1-1/2°/30 metres. The slowest change possible to achieve the objective is usually the best.

308. Factors which affect the directional behaviour of rotary assemblies in directional rotary assemblies Increase in distance from near-bit stabiliser to the first string stabiliser - is the main design feature of a fulcrum assembly affecting the build rate. The build rate increases as this distance is increased because a longer fulcrum section will bend more which will

increase the fulcrum effect and the side force on high side. There is a limit, however. Once the upper stabiliser is more than 40 metres from the near-bit stabiliser (depending on hole size, collar OD, etc.), the collars are contacting the low side of the hole and any further increase in this distance will have no additional effect on the build rate. Increase in hole inclination - the build rate of a fulcrum assembly increases as the inclination increases because there is a larger component of the collar’s own weight, causing them to bend. Reduction of drill collar diameter - A small reduction in the OD of the drill collars used in the fulcrum section considerably increases their limberness, and hence the build rate. There is a tendency to bend the drill string near the bottom of the hole due to the weight on the bit. In harder formations, this can cause deviation problems or unwanted directional tendencies. The stiffer the collars, the more deviation control. The stiffness is a non-linear function of diameter, e.g., a 7” drill collar is approximately twice as stiff as a 6” drill collar. Increase in weight on bit - Increasing the weight on bit will bend the drill collars behind the near-bit stabiliser more, so the build rate will increase. Reduction in rotary speed - A higher rotary speed will tend to straighten the drill collars and reduce the build rate. Low rotary speeds (70-100RPM) are generally used with fulcrum assemblies. Reduction in flow rate ( in soft formations) - In soft formations, a high flow rate can lead to washing out the formation ahead of the bit which reduces the build tendency. Formation Dip - The effective dip angle is the angle at which the bit strikes the bedding planes. At formation dips less than 45 degrees, the bit will tend to build angle to become perpendicular to the bedding planes of the formation. At dips greater than 45 degrees, the bit will tend to slide along the strike or drop down the dip. The effect of formation dip is normally not serious, except in areas where the beds are hard, lay at significant angles, and are of different composition from layer to layer. Bit Types - The longer the tooth or inset on a bit, the more responsive it is to a formation. Dulled bits can reduce drilling assembly response. Bits with the least offset or skew should be used on wells experiencing deviation control problems. Bits with enhanced gauge protection are normally recommended for directional/horizontal drilling work. Conventional three-cone rock bits cause right-hand walk in normal rotary drilling. Long tooth bits drilling soft to medium hardness formation give a greater right walk tendency than short tooth bits drilling a hard formation. The gouging/scraping action of soft formation bits creates a tendency to change direction to the right; also, long-toothed soft formation bits have a greater cone offset which increases the effect. When rotary drilling with PDC bits, it has been found that almost no "walk" occurs. The gauge length of a PDC bit may significantly affect the build rate in a rotary assembly. A PDC with a short gauge length may result in a build rate greater than that which would be expected with a tri-cone bit. A longer gauge stabilises the bit, tending to reduce the build rate. The low WOB used with PDC bits may also reduce the build rate, as collar flexure decreases with decreasing WOB. When used with packed assemblies in tangent section drilling, longer gauged PDC bits seem to aid in maintaining inclination and direction due to the increased stabilisation at the bit. When used with angle drop assemblies, PDC bits may reduce the drop rate previously obtained with a tri-cone bit. The longer the gauge length of the PDC bit, the lower the drop rate obtained because the bit gauge acts similar to a full gauge near-bit stabiliser. Short gauge length PDC’s can be used effectively for dropping angle. When such a suitable PDC bit is used in a rotary pendulum assembly,

the low WOB and high RPM, typical PDC bit applications, should assist in dropping angle. Formation Hardness - In soft to medium soft formations, the rock has little influence on directional response. In medium to hard sedimentary rocks which have dissimilar properties in all directions, directional tendencies can be significantly affected by the formation. In very soft formations, the formation may be eroded by the drilling mud exiting from the bit nozzles creating an overgauge hole. This can make it hard to build angle, even with a strong build assembly. If this problem is anticipated, then fairly large nozzles should be used. If it occurs while drilling, then the pump rate should be reduced, and prior to making each connection, increase the flow rate to clean the hole with the bit one joint off bottom. Hole washing or enlargement in soft formations may also cause packed assemblies to give a dropping tendency at high inclinations. This may be counteracted by increasing WOB and reducing flow rate. If anticipated beforehand, a possible solution would be to run a mild build assembly. The main directional problem encountered in hard formations is getting a pendulum assembly to drop angle. The harder the formation, the longer it takes a dropping assembly to respond. There may also be a conflict between the need to reduce WOB to get the dropping trend established, and the need for high WOB to maintain an acceptable penetration rate. When a drop section must be drilled in hard formation, the use of large diameter, heavy collars is recommended. 309.Dogleg and dogleg severity Dogleg (DL) is the overall change in inclination and azimuth of the wellbore between two points. Dogleg severity (DLS) is the total change in the angle of the hole per 30 metres. After the kick-off point, the angle is changed under control, however any abrupt dogleg is a potential danger, and the concept of dogleg severity is useful in grading the dogleg in order to establish safe limits. When orientating a deflection tool, it is necessary to estimate the expected dogleg value for the section about to be drilled. The expected DLS will depend on the angle of the bent component within the motor. Other factors such as motor size, formations drilled, and length and hole size greatly effect DLS. The worst complication of a dogleg is the creation of a key seat. This is a continuous hazard that has to be avoided or eliminated whenever it occurs.

310.Directional control with rotary assemblies Rotary BHA’s can be designed to drill a planned trajectory. It is possible to control the angle (inclination) of directional wells during rotary drilling by correct assembly design. Control of hole direction is more difficult. See 9.2.5 for details of the main factors which effect directional behaviour of rotary assemblies. Stabilised assemblies can be used to directionally drill wells. The trajectory is controlled by a side force imposed at the bit. This side force is accomplished with combinations of drill collars and stabilisers, varying the points of tangency (where the assembly touches the wellbore) along the assembly. The following are the basic directional control principles:

311.The Fulcrum Principle. The fulcrum principle is used to build angle. This assembly uses a near-bit stabiliser and collars. The collars above the near-bit stabiliser bend, partly due to their own weight, and partly because of applied WOB. The near-bit stabiliser acts as the pivot or fulcrum of a

lever and the bit is pushed to the high side of the hole. The bit therefore drills a path which gradually builds angle. See Figure 9.1. Placement of some MWD systems between the near bit stabiliser and the first string stabiliser could result in the increased possibility of MWD failure. This is because some collar mounted MWD systems have a lower equivalent bending stiffness than drill collars with the ID, and as a result may be the most flexible part of the BHA. Proper placement of such MWD systems above the first string stabiliser can reduce the frequency of stress-related failure.

Figure 298.1 Fulcrum principle 312.Packed Hole Principle - (Locked in Assembly) If restrictions to bending the drill collars are run in the string, there would be no building effect and it would not be possible to build the angle. It will tend to maintain the angle. This principle is that if there are three stabilisers in quick succession behind the bit, separated by short, stiff drill collar sections, then the three stabilisers will resist going round a curve and force the bit to drill a reasonably straight path. The first of the three stabilisers should be immediately behind the bit (a near-bit stabiliser), and should be full gauge. Stiff or packed hole assemblies are used to drill the tangent sections of directional wells, maintaining angle and direction. The sizes of the top stabilisers are not necessarily full gauge, but in some cases must be undergauged to counteract the pendulum effect which is intended to drop the angle. 313.Pendulum Effect The pendulum effect provides controlled drop-off of the vertical angle. The portion of the assembly from the bit to the first string stabiliser "hangs like a pendulum" and because of its own weight, presses the bit to the low side of the hole. The major design feature of a pendulum assembly is that here there is either no near-bit stabiliser or an undergauge near-bit stabiliser. The length of collars from the bit to the first string stabiliser must not be allowed to bend too much towards the low side of the hole. See Figure 9.2. The following are to be considered, if using a pendulum assembly: 175.Omit the near-bit stabiliser when azimuth control is not a concern or when drilling with a PDC bit. When drilling with a roller cone bit, use an under-gauge near-bit stabiliser if azimuth control is a consideration.

176.The assembly should have two string stabilisers with the second stabiliser not more than 10 metres above the first. 177.Initially use low WOB until the dropping tendency is established, then gradually increase bit weight until an acceptable penetration rate is achieved. 178.Use high rotary speed, depending on bit type. If possible, do not plan drop sections in hard formations.

Figure 298.2 Pendulum principle 314.Non-magnetic Drill Collars In order to eliminate any magnetic interference around the single shot instrument, a K Monel or a stainless steel drill collar is used. In doing so, the compass is influenced only by the earth’s magnetism, thus giving a true magnetic reading. The length of a non-magnetic drill collar required to avoid interference from the drilling string is a function of both the direction and inclination of the hole. More non-magnetic material may be required for wells which have more inclination or bearings which deviate much from North or South. Stabilisers placed between non-magnetic drill collars must be made of nonmagnetic material. The direction drilling program should specify the amount and placement of non-magnetic material in the bottom hole assembly. A single Monel drill collar may be used when directionally monitoring a vertical well. 315.Short drill collars, extension subs These are tools that help to change the distance between the stabilisers, or between bit and stabilisers, in order to change the stiffness of the BHA.

316.0Bottomhole assemblies with responses under ideal conditions

Figure 298.3 Bottomhole assemblies with responses under ideal conditions (no hole curvature) 317.Selection of stabiliser type Geology is the most important consideration when choosing the right stabiliser for a well. Economics and convenience also frequently influence the selection of one stabiliser type over another. In order for a bottomhole to maintain a straight course or build or drop angle at planned rates, stabiliser blades must maintain the desired gauge while they are in the hole. Excessive wear (undergauge) on stabilisers severely decreases the stiffness of the bottomhole assembly and will cause unwanted angle change. A small variance in gauge can result in unsatisfactory BHA in directional wells. Durability is the key in stabiliser design, and geology is the most important factor in selecting stabilisers for long wear life. In general, the harder and more abrasive a formation is, the more durable the drill string stabilisation tools have to be. Choosing hardfacing material for blades is determined by formation hardness. Use only integral blade stabilisers. Long blades provide better stiffness in packed hole assemblies. Avoid cross-over subs whenever possible. Any connection makes an assembly more limber and adds a potential failure area.

Reamers should not replace stabilisers except in very hard formations, or when stabiliser torque becomes excessive.

Figure 298.4 Directional drilling terminology 318.Types of directional patterns Most directional wells are still planned using the traditional patterns which have been in use for many years (see Figure 9.4). The following are the most common patterns used:

Build and Hold (see Figure 9.5). S Type Well (see Figure 9.6). Deep Kick-off and Build. Horizontal. Sidetracking.

Figure 298.5 Build and hold pattern

Figure 298.6 S type well pattern 319.Kick-off point and build-up rate The higher the kick-off point selected, the lower the maximum required hole angle, but the earlier the directional drilling comes into effect. Other considerations when utilising a relatively high kick-off point include:

320.Potentially greater chances of forming a key seat in the build-up section due to a longer period of exposure and typically being located within a softer formation. 321.Reduced chances of differential sticking adjacent to the porous intervals downhole due to lower hold angle. 322.Generally greater difficulty in building angle in the softer formation. 323.Reduced likelihood of unstable wellbore conditions resulting from drilling sensitive layered formations at high hole angles.

The selection of both the kick-off point and the build-up rate depend on many factors, including the hole pattern selected, the casing program, the mud program, the required horizontal displacement, and the maximum tolerable inclination. Choice of kick-off point may be severely limited by the requirement to keep the well path at a safe distance from existing wells. Hole angles much less than 10 degrees are undesirable as angle holding assemblies are relatively unpredictable at this angle. Hole angles much greater than 30 degrees are undesirable due to the increased risk of hole problems. Maximum build is generally 2.5/30 metres.

324.Factors affecting trajectory control of rotary assemblies Rotary BHA’s can be designed to drill a planned trajectory. It is possible to control the angle (inclination) of directional wells during rotary drilling by correct design of the assembly for the drilling parameters. Control of hole direction is more difficult. The following are the main factors which affect directional behaviour of rotary assemblies: Formation dip. Bending characteristics of the drill string. Formation hardness. Bit types. Weight on bit. Rotary speed. Flow rate. Rate of penetration. Gauge and placement of stabilisers. 325.Deviation control on vertical holes The general deviation control guidelines are: 326.Attempt to control deviation below 1 degree on surface hole to prevent future surface casing wear. 327.Attempt to control deviation below 3 degrees on intermediate and main hole with a maximum change of 1 degree/30m. Deviation control can be costly due to slow penetration rates and extra trip time. The following methods may be used to control deviation: Controlled Weight on Bit. By reducing the WOB, the bending characteristics of the drillstring are changed and the hole will tend to drill straighter. The downside of using this method is that penetration rates are usually significantly reduced. The amount of WOB reduction required will vary for any given area. Pendulum Assembly. Another method to reduce deviation is to use a single stabiliser, placed 9 - 18m from the bit. This will impact a negative side force at the bit, and the hole will tend to drop angle. Stiff Assembly. The simplest stiff assembly is to increase the size of the drill collars being used, which is especially applicable for the surface hole. Stabilised packed hole assemblies are a solution for deviation problems in the main hole. Although this

assembly may prevent the angle from continuing to build, it will have a tendency to maintain the angle already in the well. If uphole deviation has been a problem and a considerable amount of hole is being drilled below the problem area, consideration should be given to running a key seat wiper in the drill string to reduce the chance of developing and getting stuck in a key seated area. 328.Kicking off The typical directional well is first drilled vertically, then "kicked off" with a deflection device (i.e., a bent housing and mud motor) to initiate a build inhole inclination. Once sufficient angle is attained, the desired well path is drilled using the following types of rotary assemblies: 329.Fulcrum. 330.Packed hole. 331.Pendulum. Getting "kicked off" from vertical can be achieved in a number of ways, but is most efficiently done using a mud motor with a bent housing. Adjustable bent housing can be readily changed from 0 to 2 degrees in 1/4 degree increments. Choices of positive displacement type mud motors will vary from low speed/high torque types to high speed/low torque types. The exact type of motor used should be chosen while programming, considering the type of formation to be drilled and motor performance history in the area. At the beginning of the kick-off the motor with bent housing can be used to build the desired inclination and azimuth. Very often left hand lead must be built into the starting azimuth to compensate for right hand bit walk expected later while rotary drilling. The desired starting azimuth should be achieved as soon after kick-off as possible. Simultaneous change of azimuth and inclination should be minimised. This can lead to severe doglegs. 332.Using the mud motor for drilling and trajectory change The surface standpipe pressure reflects the PDM torque. As the motor torque increases, the standpipe pressure increases; as the motor torque decreases, the standpipe pressure also decreases. The standpipe pressure or a downhole torque indicator should be used as a primary output indicator to advance the bit. The torque the PDM experiences is: 179.The torque required to overcome the off-bottom torque so that the rotor can rotate against the stator and against the friction of the bearings. 180.The torque required to drill a given formation with a specific bit, bit diameter, bit speed, and WOB. 333.Positive Displacement Motors (PDM) The most common mud motor used is the positive displacement motor (PDM). These motors are available in 1/2 lobe configurations for high-speed or multi-lobe configurations for low speed/high torque applications, see Figure 9.7. A 1/2 lobe motor means that the rotor has one lobe or tooth and the stator has two lobes or teeth. Motor torque increases as the number of lobes increases, with a proportionate decrease in bit speed. Either

configuration is available with an adjustable bent housing located between the motor and bearing assembly. The bent housing is easily rig adjustable from zero to a two degree bend in quarter degree increments. The adjustable bent housing being located close to the bit provides easier control of angle build rate and also allows the motor to be rotated in the hole during straight hole drilling.

Figure 298.7 Moineau motor configuration The PDM consists of helicoid motor section, a dump valve, a connecting rod assembly and a bearing and shaft assembly. The helicoid motor has a rubber-lined spiral cavity with an elliptical cross-section which houses a sinusoidal steel rotor. As the mud is pumped under pressure from above, it is force downwards between the rotor and stator. In order for the drilling mud to progress through the motor section, it must force the rotor to turn. The bottom of the rotor moves in an ellipse and this eccentric motion is converted to true concentric drive shaft rotation by the connecting rod assembly. 334.By-pass valve The by-pass valve allows fluid to fill the drill string while tripping in the hole and drain while tripping out or making a connection. While mud is being pumped, the valve closes to cause fluid to move through the tool. The valve consists of a sliding piston, or throat, a coilspring, a sleeve seat and external ports. When there is no fluid circulation, the spring holds the piston in the up position. This opens the external ports and allows fluid entry and exit through the sides of the valve body. When fluid is pumped through the drill string, the piston is forced down, which closes the external ports. This directs all fluid into the motor. When pumping ceases, the spring returns the piston to the up position. 335.Motor section The motor section consists of a rubber stator and coated steel rotor. The stator tube forms the outer body of the motor assembly. When the motor is assembled, there is a continuous seal along its length between the rubber stator and the matching contact points on the spiral rotor shaft. As drilling fluid is pumped through the cavities between the rotor and stator, the hydraulic pressure causes the shaft to rotate within the stator. As mud is pumped through the motor, it fills the cavities between the dissimilar shapes of the rotor and stator. The rotor is forced to give way by turning. It is the rotation of the rotor shaft which is eventually transmitted to the bit. 336.Connecting rod assemblies Since the rotor is spiral shaped it does not rotate concentrically, rather it traces a back and forth motion. This motion must be converted back to concentric motion to be

transmitted to the bit via the drive sub. A flexible connecting rod, attached to the lower end of the rotor, transmits the torque to the drive shaft assembly. The connecting rod converts the eccentric rotary motion of the rotor to true concentric drive shaft rotation. Flexibility in the connecting rod assembly is achieved with two opposing lobes which act as universal joints. 337.Bearing section A bearing-supported drive shaft transmits the motor's rotational and thrust power to the drilling bit. The assembly has three main bearing sub-assemblies. The only externally rotating portion of the motor is the bit sub, which is actually the lower part of the drive shaft. The output drive shaft is supported by radial roller bearings and three spherical roller thrust bearings. The axial compressive force of the bit is evenly distributed over two of the thrust bearings, while the third thrust bearing carries the axial extension forces. 338.General guidelines for PDM motor usage 181.Each mud motor has a recommended range of flow rates and subsequent RPM ranges. The mud motor should be operated within the published ranges for optimal results and prevention of damage. 182.Monitoring surface pressure is necessary in determining how the motor is performing. Each motor has a recommended differential pressure (difference between off bottom and on bottom pressures) and motors should be operated near this pressure. A further increase in surface pressure is an indication that the motor is stalling. The RPM of a motor is controlled by the flow rate. Increasing torque (by WOB) does not significantly affect the RPM of a motor unless it is stalled. Torque is directly proportional to pressure differential across the motor. More weight on the bit (thus an increase of torque requirement) means higher surface fluid flow pressure. As the bit drills off, this pressure decreases. Therefore, the mud system pressure gauge can be used as an accurate weight and torque indicator. The instant the motor experiences a load change, the pressure gauge reflects a proportional change. 183.High speed motors exhibit low torque and, therefore, cannot accommodate high WOB's. Low speed motors, which can develop high torque, should be used where increased WOB is desirable. 184.All positive displacement motors exhibit left-hand torque when on bottom. Therefore, allowance for this torque is necessary when orienting the motor. The amount of allowance is dependent on the type of mud motor and formation. The high torque of a low-speed motor can cause significant problems in orientation control, and it therefore may be desirable to utilise a measurement while drilling system (MWD) to continuously monitor the tool face. 185.If a motor is rotated 20-30 RPM on the drillstring at the surface, than this is all that is normally required. 186.Most mud motors are equipped with a dump valve assembly which will allow fluid to drain while coming out of the hole. 339.Adjustable bent housing Bent housing is a patented device which is easily field adjusted from zero to two degrees by quarter degree increments.

The housing consists of a mandrel and a sub, each having an offset axis. Rotating the sub about the mandrel produces the desired bend in the housing. The bend is positively locked in position by simply engaging the toothed dog clutch and tightening the lock nut. The adjustable bent housing is located between the bearing and motor assemblies which places the bend point close to the bit. This provides easier control of angle build and allows the motor to be rotated in the hole to continue drilling the tangent section until a directional correction is required. Rotation of the drillstring is then stopped, the tool face is oriented in the required direction, and the correction is made using the motor only. Following the correction, rotation of the drillstring is resumed and drilling continues. For medium and short radius drilling, a second adjustable bent housing can be fitted between the motor section and the by-pass sub. This housing also includes an orientation sub which can be easily adjusted to align the bends of the upper and lower bent housings. To adjust housing: Back off lock nut and disengage dog clutch. Rotate to match numbers of desired angle. Re-engage dog clutch and torque lock nut. 340.Reaming When it is necessary to ream the directional hole the reaming BHA must be stabilised properly, not too stiff on the bottom, and the string reamers and stabilisers should be placed properly, in order to ream the minimum possible. The biggest danger in reaming is to undercut the well and sidetrack it at the low side of the hole.

341.Fatigue in directional drilling An abrupt dogleg can cause stress on the drilling assembly components, raising the possibility of failures by fatigue. High tension on the drillpipe, because of a heavy BHA, is the factor that should be checked when a drillpipe failure occurs. The BHA should not normally contain more than 10 or 15% more weight than the drilling weight required. Fatigue failures are bound to be present, especially when a heavy drilling set-up is used for reaming. This is because reaming is done without weight on the bit and tension on the drillpipe is at its maximum.

342.Fishing in directional drilling When a fishing job is necessary in a deviated hole, the fishing operations to follow are the same as the ones in a straight hole, with the advantage that the top of the fish will always be laying at the low side of the hole, so catching the fish will not be too difficult as long as the hole is not washed out. In a directional well, it is good practice to work the pipe whenever the drilling is stopped and keep the hole filled. Due to the inclination of the hole, the danger of differential sticking is higher than in a vertical well. 343.Tool face orientation Once the desired direction the tool should be facing is determined, the next step is to actually face the tool in that direction, in order to drill the predetermined course.

When kicking off a well, there must be a change in the direction plane or the inclination plane. Some method must be used to force the bit in the desired direction. The magnitude of the deflection is controlled by the departure from the centre line of the deflecting tool (the bent housing). All settings are to high side or to the left or right of high side. They are called "high side tool face" settings (see Figure 9.8).

Figure 298.8 High side of the wellbore The precise result obtained from a particular tool face setting will vary in different situations, and is affected by the formation and by other factors such as hole size and drilling parameters. Whatever the inclination of the well, the effect of setting tool face on high side, i.e., in hole direction, is to build angle and keep direction constant; conversely, setting the tool face on low side will always give the maximum possible drop rate while holding direction. There are several methods available for remotely aiming the direction of the bent-housing motor during directional drilling operations. Mule Shoe Orientation: This method uses a direct mechanical alignment of tool face and instrument package. This requires the use of either a mule-shoe mandrel and bottom-hole orienting sub. The muleshoe orienting sleeve is positioned in the mule-shoe orienting sub to line up with the bent housing knee. The single shot tool has a mule-shoe mandrel on the bottom that is shaped to go in the orienting sleeve, only in the direction of the tool face. A key, located in the drilling assembly, is locked into exact alignment with the true face direction of the deflection device. The lower end of the survey instrument assembly has a complimentary keyway (shaped like a mule's shoe) that slides onto the key and aligns the single-shot survey instrument with the tool face. A survey picture taken with this system provides hole direction and inclination angle, as well as the tool face or orientation.

344.Horizontal Drilling 345.Horizontal drilling pattern

Figure 298.9 Horizontal drilling pattern 346.BHA weight and weight on bit The bottom hole assembly should provide the desired weight on bit. It has long been standard practice when drilling vertical wells to avoid running ordinary drill pipe in compression. This practice was also adopted on low-angle directional wells. In highly deviated wells, when high WOB is required, then a long and expensive BHA is required for the drillpipe to be in compression because only the along-hole component of the weight of BHA elements contributes to the weight on bit. Drillpipe is run in compression because researchers have shown that it can tolerate significant levels of compression in small-diameter, high-angle holes because of the support provided by the low side of the hole. When drilling horizontal wells drillpipe is commonly run in compression, apparently without causing damage to the pipe.

347.Survey Equipment and Procedures The trajectory of a wellbore is determined by the measurement of the inclination and direction at various depths. This section presents the various measurement tools, the principles of operation, and the necessary corrections: Drift Measurements. Magnetic Surveys. Azimuth Reference Systems. Gyroscopic Survey Tools.

Measurement While Drilling (MWD). Directional Survey Calculations. Magnetic Declination Correction. Magnetic Interference and Instrument Spacing. Magnetic Single Shot Surveys - Unloading, Developing and Reading the Film. Surveying Inaccuracy. 348.Drift surveys The inclination of a borehole is the angle between the borehole axis and the vertical axis. Drift surveys provide only inclination information with no indication of wellbore direction. Drift surveys are used frequently in the vertical section of the hole above the kick off point. As the direction of deviation is not known, uncertainty is created which can be calculated by assuming the deviation is an all-in-one direction, and then rotating this potential horizontal displacement versus depth around the well bore axis to create the uncertainty limits in any direction. This tool is run on wireline and needs approximately one to two minutes of stopped rotation and circulation to obtain a survey. It is Coparex company practice to take surveys every 30 m on surface hole, and every 100m on main hole. 349.Magnetic surveys Magnetic surveys can only be run in open hole. This is due to the disruption of the magnetic signal that would occur if the survey were run inside the casing. Magnetic surveys are usually run in the drillstring and must be located adjacent to non-magnetic drill collars. These types of collars are required to allow the survey instrument compass to locate magnetic north. The azimuth of a borehole at a point is the direction of the borehole on the horizontal plane, measured as a clockwise angle (0 - 360 degrees). Hole direction is measured with respect to magnetic north. The correction to true north must be made for the specific area. The size of the correction depends on the location of the well, and may be only a few degrees to 45 degrees or more in northerly areas. There are two types of magnetic surveys: 350.Magnetic Single-Shot Surveys. The magnetic single-shot survey tool records one inclination and direction per run. The tool is run on wireline and uses either a motion sensor, a Monel sensor or electronic timer to activate the camera and film disk. While the surveying picture is being taken using the motion sensor method, the pipe must not be moving and the circulation must be suspended. Using the timer method, timers on the survey instrument are present to allow sufficient time for the survey to reach bottom before the shot is taken. The nonmagnetic collar sensor can also be used instead of the electronic timer. It will cause the single shot camera to take a survey picture after the instrument has been in a nonmagnetic drill collar for 60 seconds. It eliminates the need to guess the time for the tool

to reach bottom. It is not sensitive to downhole vibration which can prevent the motion sensor from taking a picture. The survey units come in various angle ranges and the most accurate scale for a given hole angle should be used. The normal procedure for magnetic single shots taken is to drop the tool to "free fall" through the mud to bottom prior to a bit trip. The tool is usually recovered with an overshot after all the drillpipe has been tripped out. Single shot magnetic surveying is slow, but is the least expensive system. However, MWD systems can be more economic if very frequent surveys are required, such as during angle building or when penetration rates are high. Electrical power is furnished by batteries. The electrical circuit is controlled by a timer which closes the circuit and causes the lamps to illuminate at the pre-set time. The inclination and direction of inclination indicated by the compass-angle unit are recorded on a film disc. This instrument can be used to make orientation surveys for any deflecting tool being used. There are four basic components which make a magnetic single shot instrument: 187.Compass/angle unit (see Figure 9.10). 188.Camera. 189.Timing device. 190.Battery pack. All these angle units contain a magnetic compass card which aligns itself to magnetic North and provides the direction reference. The low ranges have a plumb bob unit which hangs above the compass card from a single suspension point. The plumb bob will always hang vertically, regardless of the inclination angle to which the instrument is tilted. When the instruments are vertical, the point of intersection of the cross hairs on the plumb bob is directly above the centre of the compass card. If the angle unit is tilted over at an angle, the intersection of the cross hairs will be vertically above some point displaced outwards from the centre of the compass card. The compass card is calibrated with concentric rings which represent increments in inclination. Since the plumb bob always hangs vertically, a straight line through the centre of the compass card and the point of intersection of the cross hairs will indicate hole direction on the compass scale. The only correction which has to be applied to the single shot reading is the magnetic declination correction.

Figure 298.10 Angle unit 351.Magnetic Multi-shot Surveys. Multi-shot magnetic surveys are able to record the magnetic direction and inclination of an uncased hole on a film strip at multiple stations with a single loading by using a reel of film which is advanced by a present timer. The tool is normally dropped down the hole prior to a trip out of the hole. The downhole tool is positioned in a non-magnetic drill collar so that the magnetic compass is spaced as far as possible from any magnetised steel. Care must be taken to accurately record the depth of each stand or single where surveys have been recorded. The electronic magnetic multi-shot (EMS) uses a sensor array of accelerometers and magnetometers housed in an electronics probe. The data is recorded downhole on a memory chip and then transferred to a computer disc for processing when the tool is retrieved at surface. 352.Magnetic single-shot surveys - unloading, developing and reading the film 353.Unloading and Developing the Film Recover the instruments and unscrew the camera/angle unit assembly from the timer. DO NOT separate the camera from the angle unit at this stage or the film will be exposed. Pull the bottom of the developing tank off. Make sure the tank's light trap operates freely (normally firm). Fill the bottom of the tank with 1 mm of developing fluid. Push the top of the tank completely into its bottom cup. Place the tank on a firm surface and open the light trap.

Place the camera/angle unit over the tank and mate the lips of the tank with the film gate notch in the camera. Press the camera's film gate button. Shut the tank's light gate. Allow the film to develop for four minutes, agitating the tank occasionally. If the fluid is cold, develop the film for 8 to 10 minutes.

Figure 298.11 Single shot instrument 354.Reading the film 191.0-10 and 0-20 disks - Line up the reader’s cross hair so that it intersects the centre of the disk and the centre of the plumb bob cross hair. Read the directions where the reader’s cross hair intersects with the compass card. Read inclination from where plumb bob cross hair intersects concentric inclination circles. The third piece of directional information read from the disc is the tool face orientation. This is only of interest when the single-shot is being used to orient downhole deflecting tools. The tool face line is the heavy black line extending from the outer edge of the disc inward . The tool face reading is obtained by the relationship of the tool face line to the scale on the disc viewer. See Figure 9.12.

Figure 298.12 Degree angle unit (0-10 degree) 192.15-90 disks - When reading the high inclination picture, the disc is oriented so that all alphanumerics are right side up. Read the inclination at the intersection of disk's centre horizontal cross hair and vertical scale. The azimuth is read from the intersection of the vertical line and the respective point of the compass. The tool face line is the heavy black line extending from the outer edge of the film disc inward. The tool face, when using the single shot to orient downhole tools, is read from the relationship of the tool face line to the scale on the viewer. See Figure 9.13.

Figure 298.13 Degree angle unit (0-90 degree) 355.Azimuth reference systems For directional surveying there are two azimuth reference systems:

Magnetic North. True (Geographic) North. Magnetic type tools initially give an azimuth (hole direction) reading referenced to magnetic north. The final calculated co-ordinates are always referenced to either true north or grid north. True (geographic north) is the direction of the geographic north pole which lies on the axis of rotation of the earth. This direction is shown on maps by the meridians of longitude. Survey tools measure the direction of the wellbore on the horizontal plane with respect to the north reference, whether it be true or grid north. There are two systems used: Azimuth - In the azimuth system, directions are expressed as a clockwise angle form 0 to 359.99 degrees, with north being 0 degrees (see Figure 9.14). Quadrant Bearings - In the quadrant system, the directions are expressed as angles from 0 90 degrees, measured from north in the northern quadrants and from south in the southern quadrants (see Figure 9.15). Figure 9.16 illustrates how to convert between the azimuth and quadrant bearing system.

Figure 298.14 Azimuth

Figure 298.15 Quadrant bearings

Figure 298.16 Azimuth-quadrant conversion

356.Gyroscopic surveys Gyroscopic surveys can be run in either cased or open hole and do not require the use of non-magnetic drill collars. Gyroscopic survey tools rely on a motor-driven gyroscopic (highspeed rotating disks). The gyroscope systems are aligned to a suitable datum point at surface, usually before the tool is run. It operates like the magnetic single shot, taking a picture of the direction of the bore hole, related to the gyro orientation. A pendulum gives the inclination of the hole. Gyroscopic surveys are most commonly used as multi-shot instruments run inside casing. 357.Measurement while drilling (MWD) MWD systems have been designed and used as a means of improving the efficiency of the drilling operation by minimising lost time due to time consuming activities such as borehole surveying and wireline logging (steering tool). An MWD system can be used to transmit a variety of measurement data from downhole to surface, without the complexities of an electric wireline. All MWD systems use sensors located in the bottomhole assembly to monitor drilling parameters and/or formation characteristics. At the surface, the signals are received by a pressure transducer and transmitted to a computer that processes and converts the data to inclination, direction, and tool face orientation. This information is transmitted to a terminal, which prints it, and to a rig-floor display which displays inclination, direction, and tool face orientation. A basic MWD system contains these essential components: 193.Downhole sensor package 194.Surface computer to receive data and convert it to a useable format 195.Uphole or surface sensor (for reception of data signal from downhole) 196.Downhole power source 197.Method to transmit data from downhole to surface and/or to record data 198.Downhole computer (microprocessor and electronics for controlling and monitoring the downhole system). Different MWD systems now available offer a growing selection of downhole sensor packages able to monitor various downhole parameters. These parameters can be sorted into three broad categories of information. Directional information comprises wellbore inclination, azimuth and tool face orientation. Formation evaluation MWD initially included only gamma ray and receptivity. More recently, neutron and density measurements are possible. Engineering information can include true downhole weight and torque at the bit, annular temperature and pressure. 358.Description of Mud Pulse Telemetry Mud pulse telemetry has the ability to transmit continuously while drilling without interrupting the normal productive drilling program. Interfacing to the rig’s mud circulating system is simple (no modifications to the existing equipment are required). Information encoded in a binary format is transmitted to the surface by either a positive or negative pressure pulse generated in the drilling fluid. Positive pulse systems use some type of internal restriction to produce a pressure pulse above ambient pressure. It has the advantage of better signal reception over negative pulse. Negative pulse systems use a bypass valve to vent flow from the inside of the tool into the annulus, thereby creating a pressure pulse below ambient pressure. An advantage of negative pulse telemetry is ease of flow due to minimal flow restriction. As a result, erosion is less

of a problem and pumping of lost circulation materials and cement plugs is more easily achieved. 359.Downhole Power Turbine generated power is dependent on an adequate flow rate, and is prone to erosion, but is less prone to temperature or time limitations than battery packages. Turbines can also provide longer and higher rates of power transmission. As more sensors are added to MWD downhole systems, increased availability of power becomes a necessity. Drillpipe mud screens are necessary when using turbine powered MWD systems. 360.Retrievable probe versus collar mounted systems Sensors contained within a retrievable probe restrict flow and are prone to erosion. The retrievable based MWD can be advantageous in situations involving drillstring sticking; whereby the probe can be retrieved, lessening the overall lost-in-hole costs. The downhole probe can be repaired or module modified rather than tripping the entire BHA out of the hole. Retrievable and free hanging/standing probes have the advantage of being able to withstand much greater build rates than collar mounted systems. Collar mounted systems can usually withstand greater stresses from shock and vibration, and can be more easily configured for high flow environments. 361.Formation Evaluation (Logging While Drilling - LWD) The object of resistivity measurements is to examine the properties of the formation’s natural fluids and determine the content. Oil, water and salt water all have different abilities to conduct electricity. Since drilling fluids tend to permeate out into the formation, measuring the resistivity beyond the zone invaded by the drilling fluids is necessary. Formation evaluation MWD has the advantage of measuring resistivity soon after the formation is drilled, and prior to full invasion of the drilling fluids into the formation. Transmitting formation evaluation information (measurements must be related to given depths) has led to the development of downhole memory capabilities where formation evaluation data is not transmitted, but stored for downloading at surface. 362.Directional survey calculations The normal method for determining the well path is to determine the co-ordinates by using some type of surveying instrument to measure the inclination and direction at various depths (stations) and then to calculate the trajectory. Trajectory path surveys are taken at stations. At each station, inclination and direction angles are measured, as well as the course length between stations. Each direction angle obtained by a magnetic type of survey must be corrected to true north, and each gyroscopic must be corrected for drift prior to calculating. MWD readings are corrected for magnetic declination by computer at surface. The following are the three most popular methods of calculating directional survey information: Average Angle - Most popular calculation for hand held calculators. Radius of Curvature Minimum Curvature.

363.Magnetic declination correction The amount of correction required can be found on the directional plan provided by the directional company. See Figure 9.17 for adding or subtracting this correction from each and every survey.

Figure 298.17 Magnetic declination correction Surveying instruments that are used to measure the wellbore direction on the basis of the earth’s magnetic field must be corrected for the difference between true north and magnetic north. Declination is the angle between magnetic north and true north. The compass reacts to the horizontal component of the magnetic field; the reaction decreases when the compass is moved northward. When magnetic north lies to the west of true north, this gives a WEST DECLINATION CORRECTION. Since any magnetic survey is referenced to magnetic north, the observed azimuth is greater than the true azimuth. Therefore, the declination correction is subtracted from the observed azimuth. If magnetic north lies to the east of true north, this gives an EAST DECLINATION CORRECTION (see Figure 9.18). The observed azimuth is less than the true azimuth. Therefore, the declination correction is added to the observed azimuth.

Figure 298.18 East magnetic declination correction 364.Magnetic interference and instrument spacing The sensors in magnetic survey tools detect the earth’s magnetic field. However, if there are other sources of magnetic fields (see Figure 9.19) nearby, these will also affect the sensors. The readings are affected by magnetic interference. There are numerous possible causes of interference, including: 365.Drillstring magnetisation. 366.Nearby cased wells. 367.Nearby fish: if the well has been sidetracked. 368.Magnetic deposits in the formation. 369.Magnetic storms. 370.At shallow depths, the platform structure itself.

Figure 298.19 Source of magnetic interference The Effect of Drillstring Magnetisation As the drilling assembly is rotated in a borehole, the steel components become magnetised. Nonmagnetic drill collars do not become magnetised and are used to space magnetic-type survey instruments as far as possible from magnetised steel. Downhole, the survey tool lies inside one of the Monel collars. The number of Monels required depends on various factors: the horizontal component of the earth’s magnetic field, the inclination and the azimuth of the well. For example, high angle wells require more Monels in general, and more Monels are required when drilling east. Figure 9.20 is a guideline to the length of non-magnetic collars required for the different directional scenarios. Care should be taken to ensure that all crossovers, stabilisers, etc., placed within the non-magnetic collar string are also nonmagnetic. Rule of Thumb for Spacing The spacing of the angle unit compasses is given as a percentage of the total length of Monel in the BHA. The spacing is the height of the compass above the bottom of the entire Monel section.

371.Consider how much steel there is below the non-magnetic section. Less than a 3 metre section is considered minimum; 3 - 6 metres is the intermediate case; greater than 6 metres is the maximum, particularly if a downhole motor is being used. Minimum steel below Monels space at 33% approx. Intermediate case space at 35% - 45% Maximum steel below Monels space at 45 - 50% 199.Do not position the compasses within 3 metres of any tool joint. 200.Do not position the compasses within 1.5 metres of a non-magnetic stabiliser.

Figure 298.20 Magnetic interference and instrument spacing 372.Surveying inaccuracy Both magnetic and gyroscopic survey instruments can be inaccurate. Magnetic compasses are subject to magnetic interference by the surrounding drillstring, and are effected by the earth position of the survey. The conventional gyroscope has a drift error because of the earth spin, and the earth position of the survey. Along with the major measuring problems there may be errors caused by magnetic storms (which can change the north reading), declination variation, hot spots on the non-magnetic collars, or inaccurate readings. All the inaccuracies can be shown to be systematic and can be related to five major categories: compass reference, compass instrument, inclination, misalignment, and depth errors.

373.Recommended Bottomhole Assemblies 374.General The assemblies provided in the following sections are based upon North Sea experience. The assemblies are a general guide only. BHA characteristics will change with varying formation characteristics. 375.Drill collar size election Drill collar size selection should be made after careful consideration of weight on bit requirements, hole deviation, ease of make up and break down, handling safety and hole size and conditions. The use of 9 1/2" drill collars should be considered for larger hole sizes, when practical.

376.String weights Drill collar string weights (in mud) should exceed the required weight on bit by at least 10 percent. Drillpipe, jar and heavy weight drillpipe should be run in tension wherever possible. In vertical holes where the hole diameter exceeds the heavy weight drillpipe tool joint diameter by more than 4", the heavy weight pipe must always be run in tension. 377.Problem Holes If the potential for stuck pipe exists, run the minimum number of drill collars possible. If the potential for differential sticking exists, run a short, well stabilised BHA with spiral drill collars. Increase the number of heavy weight drill pipe to give the required weight on bit, if practical. 378.Deviated hole If deviated hole is to be drilled, the deviation contractor will generally advise what BHA structure is the most appropriate. 379.Key Seating If key seats develop (or may develop), an under gauge stabiliser or key seat wiper should be run between the top drill collar and the heavy weight drill pipe. The difference between key seat wiper size and drill collar size should be substantial in larger hole sizes. A full gauge stabiliser is generally run for an 8-1/2" hole and smaller. e.g.,

9-5/8" stabiliser on 8" drill collars in 12-1/4" hole. 12-1/4" stabiliser on 8" or 9-1/2" drill collars in 17-1/2" hole.

380.Float subs A float sub should be considered when drilling a 24/26” diameter hole. It should be positioned above the near bit stabiliser. This will avoid the possibility of bit plugging and to allow surveys to be taken without backflow. After making up the BHA, fill up the string and break circulation to check that the float is operating satisfactorily. Run in the hole slowly to avoid pressure surges and fill the string at least every 5 stands to reduce the pressure differential across the float. The float must not be held in the open position when tripping.

CAUTION: If the well kicks with a float sub in the string, the shut-in drillpipe pressure may be wrong. Several methods can be utilised to open the float so that the shut-in drill pipe pressure (SIDPP) can be determined. The two most widely applied methods are described in 9.5.8 and 9.5.9.

381.Static method Pump slowly down the drillpipe with the annulus shut-in. Closely monitor the shut-in casing pressure (SICP). When the casing pressure begins to rise shut off the pumps and record the drillpipe pressure. This will be equivalent to the SIDPP. 382.Dynamic method Pump down the drillpipe slowly bringing pump rate up to kill speed while holding casing pressure constant (subtract choke line friction loss if known). When kill speed has been reached, read the DP circulating pressure. Subtract slow circulation rate pressure from DP circulating pressure. This will be equivalent to the SIDPP. 383.Circulating Subs They are generally used when drilling smaller diameter holes (8-1/2" or less) but may be advantageous, in some cases, in larger hole sizes. It is activated by dropping a ball down the string and pressuring up. If one is to be run, ensure that the ball will pass through all string components.

384.Vibration control (shock subs) If an excessive drillstring vibration is anticipated a shock sub should be included in the BHA. Placement should be as close as practical to the bit.

385.Drilling Jars Although drilling jars are included in the recommended drilling assemblies, consideration should be given to omitting them from the BHA in 24" and 16" hole sizes, if hole problems are not anticipated:

386.Offshore rigs are to have at least one jar on board from spud. 387.When harsh drilling conditions are expected (e.g., long chalk intervals) the larger and more robust drilling jars should be considered, such as the 8.5" heavy duty jars, rather than the normal 8" size. 388.When drilling through formations which generate sever string vibrations (e.g., chalk) 81/2 " heavy duty jars should be used. 389.Where practical, the use of 9-1/2" jars should be considered for larger hole sizes. 390.Rotating and jarring hours are to be recorded and the details provided to the service company. 391.The service company should be consulted for advice on jar (and accelerator) placement. 392.If jars are used in KMg mud they have to be ordered with a special coating on the mandels. 393.Drillpipe strainers Drillpipe strainers are not to be used.

394.Straight hole BHA's Pendulum Assemblies (Rotary)

395.Care should be exercised when using PDC bits on pendulum BHA's. The low weight on bit values may not be sufficient to overcome formation walk tendencies and the longer gauge of the bit may act as a near bit stabiliser. Packed hole assemblies should be considered. Recommended Pendulum Assemblies: 24" - 16" Holes

12-1/4" Holes

BIT 3 x DC STAB 2 x DC STAB DC’s Jar 1 x DC HWDP

BIT 2-3 x DC STAB 1-2 x DC STAB DC’s Jar 1 x DC HWDP

8-3/8" Holes

5-7/8" Holes

BIT 2 x DC STAB 1 x DC STAB DC’s Jar 1 x DC HWDP

BIT 1 x DC STAB SDC STAB DC’s Jar 1 x DC HWDP

396.Stiff (packed hole) assembly The following assembly structure can be used irrespective of hole size:

Bit NBSTAB SDC STAB 1 x DC STAB 1 x DC STAB DC's Jar 1 x DC HWDP

397.Kick-off and deviation assemblies Kick-off and Side Track (with bent-sub)

24" Hole Bit 11-1/4” MM BS (2 deg) 2 x NMDC DC’s Jar 1 x DC HWDP 12-1/4" Hole Bit 8” MM BS (2 deg) 2 x NMDC DC’s Jar 1 x DC HWDP

16" Hole Bit 9-1/2” MM BG (2 deg) 2 x NMDC DC’s Jar 1 x DC HWDP 8-3/8" Hole Bit 6 3/4” MM BS (1-1/2 deg) 2 x NMDC DC’s Jar 1 x DC HWDP

5-7/8" Hole Bit 4 3/4” MM BS (1 deg) 2 x NMDC DC’s Jar 1 x DC HWDP NOTE:

These assemblies can be used for correcting hole direction. The choice of bent sub angle will be effected by various factors. Choice can be influenced by formation type, length of side track window, top of hole obstructions, size of hole and the need to move quickly away from the old course. Past failures have shown that it may be better to select a higher angle bent sub and aim to achieve a short, positive kick-off. This should then be followed by a reaming trip then a DTU or drilling assembly.

398.Bottomhole assemblies tangent assemblies (Navri-drill System/DTU) 24" Hole Bit 11-1/4” DTU UGSTAB (23”, 24”) 2 x NMDC UGSTAB (22”, 23”) DC’s Jar 1 x DC

16"Hole Bit 11-1/4” DTU UGSTAB (15-1/2”, 16”) 2 x NMDC UGSTAB (15-1/4”, 15-3/4”) DC’s Jar 1 x DC

HWDP

HWDP

12-1/4" Hole 8-1/2" Hole Bit Bit 9-1/2” DTU 6-3/4” DTU UGSTAB (11-3/4”, 12-1/4”) UGSTAB (8”, 8-1/4”) 2 x NMDC 2 x NMDC UGSTAB (11-1/2”, 12”) UGSTAB (7-3/4”, 8”) DC’s DC’s Jar Jar 1 x DC 1 x DC HWDP HWDP

5-7/8" Hole Bit 4-3/4” DTU UGSTAB (5-1/2”, 5-3/4”) 2 x NMDC UGSTAB (5-1/4”, 5-1/2”) DC’s Jar 1 x DC HWDP 399.Recommended stabiliser sizes are shown. The first mentioned size is for tangent or build-up sections, the seconds mentioned will change the BHA's into angle dropping assemblies. 400.The AKO (adjustable kick-off) sub can be considered as a replacement for the above mentioned systems. The AKO is a motor with a variable angle sub attached to the bottom. At low angles (angle dependent on AKO size), the drillstring can be rotated and the BHA used as a steerable system. 401.Include the angle of the DTU housing on the BHA Sheet. 402.Angle-build rotary assembly 24" - 16" Holes Bit NBSTAB SDC (< 3m) UGSTAB 3 x DC STAB 2 x DC STAB DC’s Jar 1 x DC HWDP

12-1/4" Holes Bit NBSTAB SDC (< 3m) UGSTAB 2 x DC STAB 1 x DC STAB DC’s Jar 1 x DC HWDP

8-1/2" Holes Bit

5-7/8" Holes Bit

NBSTAB SDC (< 3m) UGSTAB 1 x DC SDC (5m) STAB 1 x DC STAB DC’s Jar 1 x DC HWDP

NBSTAB SDC (< 3m) UGSTAB 1 x DC SDC (5m) perhaps STAB SDC (5m) SDC (5m) perhaps STAB DC’s Jar 1 x DC HWDP

403.Tangent rotary assembly Bit NBSTAB SDC UGSTAB 1 x DC UGSTAB 1 x DC STAB DC's Jar 1 x DC HWDP 404.To change the above assembly to an angle dropping assembly, make up the BHA using full gauge rather than under gauge stabilisers. 405.Check trips assemblies Standard Check Trip Assembly:

Bit NBSTAB 2 x DC STAB 2 x DC Jar 1 x DC HWDP 406.For the larger hole size (16" and 24") and in problematic holes (sloughing shales, ledges), the following check trip assembly should be considered: Bit NBSTAB DC STAB 2 x DC

STAB 2 x DC JAR 1 x DC HWDP 407.The following check trip assembly should be considered for holes with numerous doglegs or course corrections, (particularly in softer formations). A check trip, using the standard check trip assembly, should be made first, to avoid beginning a new hole. This assembly is also recommended for hole sections in which "tighter" casing schemes will be run: Bit NBSTAB SDC (3-5m) STAB 2XDC STAB 2XDC JAR 1XDC HWDP 408.As particular circumstances dictate, the use of undergauge stabilisers may be considered. 409.Check trip assemblies for after DTU runs After kick-off, hole correction or normal drilling operation with a DTU or mud motor in 12- 1/4" hole or smaller, a stiff (locked) BHA must not be run. If it is necessary to follow a DTU/mud motor, run in 12-1/4" hole or smaller with a stiff BHA or casing. A wiper trip should first be made with the BHA described in 9.6.20 (standard check trip assembly).

410.Surface Deviated Holes With kick-off points as shallow as +/- 150m, inclination of up to 50 deg and dogleg severity’s of up to 2 de/10m in the build-up section, a check trip may be necessary prior to running casing. The BHA described in 9.6.20 (standard check trip assembly) should be used. 411.Intermediate Deviated Section If the deviated section is to be drilled (with DTU) and then followed by a tangent section using a rotary, a check trip should be made using the BHA described in 9.6.20 (standard check trip assembly prior to RIH with the tangent assembly. This is to smoothen the well bore prior to the stiff BHA run. As long reaming runs are often required when running through shale or soft clay sections, the inclusion of an MWD collar in the BHA should be considered to avoid inadvertently sidetracking the hole. If an MWD collar is not included in the BHA, use low WOB, RPM and pump rates.

412.Accelerator position 413.During Drilling An accelerator is recommended when difficult drilling conditions are foreseen, and it is felt that the jar will not sufficiently impact by themselves. Generally, optimum placement is 3 drill collars above the jar (Hydra Jar/ Magnum Accelerator combination), but the service company should be consulted for advice. An alternative to this assembly is to place the accelerator 1 drill collar, plus heavy weight drill pipe (sufficient to be equivalent in weight to 2 drill collars) above the jar. The recommended accelerator is the dual acting type for difficult conditions. It is available in 8.5" and 9.5" sizes. 414.During Fishing Dependent on the length and nature of the fish. Fishing contractor should be consulted for advice on optimum placement of the accelerator.

415.Sidetracking Sidetracking is also known as "whipstocking" or "kicking off", and can be defined as the operation of purposely drilling a new hole beginning at some predetermined point in an existing wellbore which by-passes the original hole. It is normally done after a wellbore has been plugged back. Sidetracking can be done in open hole or out of casing. Sidetracking out of casing involves either: Milling a section out of the casing and then kicking off a cement plug, or Setting a permanent whipstock in the casing and then milling a "window" out of the casing. Sidetracking in open hole basically involves abandoning a length of hole and setting a cement whipstock plug across the area in which the old wellbore is to be departed from. A kick-off assembly is then used to deviate from the plug and the old wellbore in much the same way as kicking off any directionally drilled well. 416.Reasons for Sidetracking in open hole Change in target - A change in target area of a well can occur while drilling a well or after the well has reached total depth. A possible occurrence is that after the planned total depth has been achieved, geological evaluation indicates that the prospective formation has either been missed or has not been penetrated at an acceptable structural location. In this case, it is often economical to plug back and kick-off the well rather than re-drill it. Fish in the Hole - Perhaps the most common cause of having to plug back and sidetrack a well is the loss of down-hole equipment in the hole which cannot be recovered or for which economics dictate that it is more economical to plug back and sidetrack than attempting to recover the fish. Hole Conditions - Hole conditions may sometimes be solved by a plug back and sidetracking operation. Where a bad dogleg or key seat has occurred, it may not be possible to drill ahead without risking getting stuck or twisting off, and a plug back and sidetrack may be required. Sometimes where lost circulation or high pressure has been encountered, the well may be plugged back, additional casing run, and the well sidetracked to avoid possible problems in the old hole.

417.Sidetracking procedures in open hole The following outline is a guideline in preparing and undertaking a sidetracking operation. Abandon any lower zones as may be necessary in the usual fashion. After the hole and mud are conditioned, trip out of the hole with drillpipe. Select a section of the hole, if possible, for sidetracking that is in gauge or near gauge and which does not contain any doglegs or key seats. Trip in the hole open-ended to the point of the bottom of the plug. It is usually desirable to run a stinger on the bottom of the drillpipe, i.e, an 31/2” stinger on 5” drillpipe. Enough stinger should be run such that the top of the stinger is above the calculated top of the cement after the cement has been displaced. A minimum of 60 metres cement plug should be set. A typical plug consists of the following: 201.water wash - usually 3m3 202.a lead slurry of neat cement Pull out of cement a minimum of 150 metres above cement and circulate out any excess cement. Continue circulating and WOC. WOC depends on the recipe of the cement. Remember that the hydrostatic head gets lost over the hardening cement section. Trip in the hole with bit, drill collars, and drillpipe and clean out excess cement. The penetration rate must be carefully monitored when drilling the cement above the sidetrack point. If the cement has not reached adequate strength, it may be necessary to stop drilling and WOC. Trip in the hole slowly to avoid excessive hydraulic surges. As a guideline, the cement is near enough if the penetration rate is about two minutes per 30 centimetres, with 5 tons of weight on bit (WOB) and 50 revolutions per minute (rpm) table speed. The directional driller should monitor the drilling rate. After the plug has been polished off, trip out of the hole with the drilling assembly and trip in the hole with the sidetrack assembly. Usually the sidetrack assembly consists of mud motor with bent housing. 418.Precautions The crews should be cautioned to slow down while going into the hole or coming out of the hole through the kick off point. If trouble is encountered in getting into the sidetrack hole on a normal trip, do not permit the crew to drill or rotate in an attempt to get into the sidetrack hole. If this occurs, picking up and turning the drillstring a quarter of a turn at a time should enable you to get back into the sidetracked hole with very little difficulty. A crippled bit has often proved successful in locating the sidetracked hole. If difficulty is encountered on trips while pulling out through the kick-off point, it may desirable to run a string reamer through this section periodically. While working the reamer through the kick-off point, ensure the bit is in the sidetrack hole. Caution should be observed while surveying or making connections, and the pipe should be kept moving as much as possible, because a deviated hole is more conducive to wall sticking than a straight hole.

If a key seat wiper is run on top of the drill collars, the cutters should be a maximum of 1 /4” to a minimum of 1/8” larger than the top drill collar. For a tapered string, a stabiliser can be run at the drill collar size and change position as well. It is usually better and easier to get away from the old hole, by making the turn between 90 and 120 degrees from the direction of the old hole. 419.Sidetracking Procedures in Cased Hole The following procedure is only to be referred to as a generic example. Site specific programs will be provided by drilling engineering for any particular operation. Running procedure for wireline set whipstock packer and milling operations. Prior to any wireline operations it is highly recommended that a casing scraper is run with several passes across packer setting depth. Run gauge ring ensuring gauge ring is maximum OD of packer and junk basket. Make up adapter kit and packer on setting tool. Check oil level in setting tool reservoir. Run in hole with CCL and packer (set on wireline). Correlate casing collars with production logs. Set packer approximately 1m above the collar. RIH with mule shoe and gyro survey tool . Make up orientation stinger to packer type whipstock and orientate using compass card. Compass card numerals are viewed looking up hole from the end of the stinger. Attach starting mill to whipstock weight shear bolt. Use double lock nut or method to ensure the nut cannot back off. RIH with whipstock assembly slowly. Do not rotate string while running in the hole. One to two metres above the packer work the string and check drag. Lower stinger into the packer. Alignment of anchor and packer alignment lug will occur automatically. Lower drill string and set down 2.5T to latch anchor assembly. To ensure anchor is latched pull 3.0T dan above string weight and drag. Shear the bolt on the starting mill with 6-8T overpull. 420.Window Milling Procedure Lower the string while rotating. Torque should occur approximately 1m below the shear bolt alignment. Continue milling until sufficient depth has been made to ensure milling off the carrying lug on the whipstock. Trip out with starting mill and make up window mill, watermelon mill and drill pipe RIH. Start milling where the starting mill left off and continue milling until completely outside of casing and 2-3 metres of formation have been drilled. Trip out of the hole. Make up new window mill, watermelon mill and string reamer and RIH.

Work and ream assembly through window section until it may be pulled through window into the casing with no overpull. Trip out of the hole to pickup motor and bit.

Contents

11. CEMENTING ......................................................................................................................I 11.1 Introduction .................................................................................................................I 11.2 Cement Types.............................................................................................................I 11.2.1 Pozmix 8000 ......................................................................................................I 11.2.2 Top hole low water loss (THLWL) ......................................................................I 11.2.3 Class "G" cement ..............................................................................................II 11.2.4 Class "G" cement plus 35% silica flour .............................................................II 11.2.5 Class "G" cement plus 35% silica flour and 10% diatomaceous earth .............II 11.2.6 Gas block cement .............................................................................................II 11.2.7 Cement and water sampling ............................................................................III 11.3 Casing Running.........................................................................................................III 11.3.1 Prior to running casing .....................................................................................III 11.3.2 Running casing ............................................................................................... IV 11.3.3 After running casing ........................................................................................ IV 11.3.4 Stab-in procedures for stinger cementations. .................................................. V 11.4 Casing Cement ......................................................................................................... V 11.4.1 General ............................................................................................................ V 11.4.2 Excess cement volumes ................................................................................. VI 11.4.3 Casing cementing spacers............................................................................. VII 11.4.4 Surface/stab-in cementation ......................................................................... VIII 11.4.5 Single-stage cementing of casing ................................................................... IX 11.4.6 Multiple stage cementing ................................................................................. X 11.4.7 Free fall plug sets (BOMB)............................................................................... X 11.4.8 Displacement type plug set ............................................................................. XI 11.4.9 Multiple-stage cementing displacement ......................................................... XII 11.4.10 Multiple-stage packer cementing ................................................................. XII 11.5 Liner Running and cementing ................................................................................XIV 11.5.1 General .........................................................................................................XIV 11.5.2 Prior to running the liner.................................................................................XV 11.5.3 Running the liner ...........................................................................................XVI 11.5.4 Setting the liner hanger (Baker Flex-Lock)...................................................XVII 11.5.5 Once the hanger is set ................................................................................XVIII 11.5.6 Working rotating liners through tight hole sections .......................................XIX 11.6 Liner Cementation..................................................................................................XIX 11.6.1 General .........................................................................................................XIX 11.6.2 Cement volumes ............................................................................................XX 11.6.3 Pre-flush spacers for liners cementations. .....................................................XX 11.6.4 Scavenger slurry displacement .....................................................................XXI 11.6.5 Main Slurry Displacement .............................................................................XXI 11.7 Squeeze Cementation..........................................................................................XXIII 11.7.1 Applications.................................................................................................XXIII 11.7.2 General ...................................................................................................... XXIV 11.7.3 Injectivity test.............................................................................................. XXIV 11.7.4 Pressures ................................................................................................... XXIV

11.7.5 Squeeze methods ...................................................................................... XXIV 11.7.6 Cement plug setting procedure ................................................................... XXV Tables

Table 11.1 MSC collar opening and closing pressure ........................................................... XI Table 11.2 MSIPC opening and closing pressures.............................................................. XIII Table 11.3 MSMPC opening and closing pressures............................................................XIV Table 11.4 Example of rotating torque record.......................................................................XV Table 11.5 Pre-flush spacers for liner cementations (Water based mud).............................XX Table 11.6 Pre-flush spacers for liner cementations (VCM) ................................................XXI

421.CEMENTING

422.Introduction Cement is used in offshore operations to:

423.Cement casing, providing a seal between casing and formation and giving support. 424.Set cement plugs to enable plug back’s and abandonment’s and/or side track’s. 425.Cure severe mud losses and other hole problems. Depending on hole temperatures, required strength, etc., a variety of cement compositions are available. Cement is supplied in bulk for offshore operations. Highly specialised contractors perform the actual cementing job. Offshore rigs are equipped with a permanently installed cement unit, normally owned by the appointed cementing contractor. Job designed cement slurries are advised by cementing contractors who has laboratory facilities available. Specialised cementing contractors also supply cement chemicals, additives to the slurries.

426.Cement Types The various types of cements used in drilling operations are discussed briefly in the following sections. These cements form the basis of the cement slurries used for cementing casings, liners, abandonment plugs and kick-off plugs. The final recipe for each cementing operation will be supplied to the rig prior to each cementation. The recipe will be based upon tests performed in the cementing contractor’s laboratory. The final recipe will provide the concentrations of chemical additives required to give the cement slurry the desired rheological, thickening time and fluid loss properties. Due to the great variety of types and concentrations of additives required for different cement recipes, it is not possible to provide standard slurry recipes.

427.Pozmix 8000 428.A blend of ordinary portland cement and small quantities of bentonite and fly ash, which act as a slurry extender and weight reducer, respectively. 429.Used for top hole cementations to a maximum depth of 2 300 m and a maximum bottom hole static temperature (BHST) of 85°C.

430.Properties: 203.slurry yield: 204.specific gravity: 205.compressive strength:

108litres/100kg 1.58sg 24hr 50bar at 38°C

431.Top hole low water loss (THLWL) 432.Ordinary portland cement dry blended with a fluid loss additive. 433.Used for top hole cementations requiring low fluid loss. Suitable for BHST's up to 50°C.

434.Properties: 206.slurry yield: 207.specific gravity: 208.compressive strength: 209.fluid loss:

106litres/100kg 1.60sg 24hr 85bar at 38°C < 100 cc

435.Class "G" cement 436.Class "G" cement, neat. 437.Used for cementing casings, liners and abandonment and kick-off plugs. Suitable for BHST's up to 110°C. 438.Recommended for use as a tail slurry where a high strength shoe bond is required and an improved annular seal is advantageous. 439.Properties 210.slurry yield: 211.specific gravity: 212.compressive strength:

76.5litre/100kg 1.9 - 2.3sg 24hr 195bar at 38°C

440.Class "G" cement plus 35% silica flour 441.Class "G" cement dry blended with 35% silica flour by weight of cement. The silica flour is added to prevent strength retrogression at higher temperatures. 442.Used for cementing casing, liners and abandonment and kick off plugs. Used in wells with BHST's greater than 110°C. 443.Properties 213.slurry yield: 214.specific gravity: 215.compressive strength:

80.5litres/100kg of blend 1.90sg 24hr 240bar at 35°C.

444.Class "G" cement plus 35% silica flour and 10% diatomaceous earth 445.Class "G" cement dry blended with 35% silica flour and 10% diatomaceous earth are added to increase resistance to strength retrogression and associated permeability for wells drilled in steam flood areas. 446.Used for cementing casing liners and abandonment and kick-off plugs. Used in wells, with BHST's between 120°C and 150°C. 447.Properties 216.slurry yield: 217.specific gravity: 218.compressive strength:

98.3litres/100kg of blend 1.68sg 24hr 60bar at 45°C

448.Gas block cement 449.These slurries should be used if there are any potentially problematic gas zones. They contain small silica spheres (3 microns) which block the pore spaces in the setting cement, preventing gas migration.

450.The use of a minimum length cement column is recommended. Apply back pressure during the curing process, where possible. The pressure must be continuously monitored, as an increase will probably occur as the cement cures. 451.The cement properties should be adjusted for each job, as required by the actual hole conditions. 452.Cement and water sampling Cement and rig water samples are to be taken, properly labelled and sent to the cementing contractor as soon as possible. Samples are to be taken as follows:

453.Cement in silos: When unloading from the boat, take samples of 5kg each from the sampling point. Ensure that clean samples are taken by cleaning the line and filter prior to receipt of cement. 454.Cement in bags: Select 4 bags at random from the stack and take 2.5kg from each bag.

455.Casing Running 456.Prior to running casing Prior to running the casing ensure that:

457.A wiper trip is made, using the check trip assembly prior to running casing if the hole section was drilled using a DTU bottomhole assembly, (greater than 121/4"). 458.The drillstring is strapped out of the hole on the last trip if there is a significant difference between drillers and loggers depths. 459.Mud has minimum practical Y.P. and gel values. 460.Casing running lists are distributed. 461.Joints to be run (and not to be run) are clearly marked. 462.A suitable landing joint is available on site. 463.Casing hanger seals are in acceptable/new condition. 464.Surge/swab pressures are known. 465.Running speeds are specified. 466.Maximum allowed overpull of casing, elevators, links, etc., are known. 467.Circulating swedges and low torque valves for all thread types in use should be available on the rig floor. Size and thread type should be clearly indicated on each swedge, including pressure rating. Running list: The running list should be made after the casing has been entirely checked and the exact setting depth is known. The running list should be ready several hours prior to running. To prepare it consider: 468.Cementing depth and length of the pocket. 469.Position of the float collar, MSC collar, (when used).

470.Position of the different weights, grades and threads of the casing (if applicable). 471.Position of the bottom flange on conductor string. 472.Position of mud-line suspension (MLS). 473.Use of hangers. 474.Position of casing collars/running string with relation to the BOP stack. 475.Landing joints, crossover nipples, pup joints, overstand, marker joints. 476.Position of centralisers in hole. 477.Required makeup torque for casing to be run. 478.List of unused casing and accessories that should remain on deck. 479.Depths at which casing shoe enters open hole or areas with poor hole conditions (washouts, tight spots, loss zones etc.). 480.Running casing While running casing ensure that:

481.Correct makeup torque is applied. 482.Once the float collar is made up it does not allow backflow. 483.After the float equipment is made up to the string, check that circulation is possible. 484.Displaced mud is diverted to the trip tank. 485.The fill-up hose is to be used between connections, stop and completely fill the string every 5-10 joints. 486.Install short joints as required for correlation purposes. 487.Specified running speeds are not exceeded. 488.Installation of centralisers, MSC collars, short joints, etc., is performed as per specifications and programme. 489.Positive centralisers above MSC to ensure standoff in critical applications. 490.Losses are minimised by reducing running speed, breaking circulation etc. (check cumulative returns). 491.Spiders are used for running casing in open hole. 492.No joints are removed from the rig site prior to the end of the job. 493.The circulations head is installed on the last joint prior to lowering. If resistance occurs circulate down. 494.After running casing After running casing check:

495.Prior to picking up the hanger ensure that the correct number of joints are left on deck. 496.The casing string should be reciprocated unless hole conditions dictate otherwise, calculate maximum rate. 497.Circulate a minimum of 120% of casing contents and carry out pump test at varying flow rates (calculate max. rate). Record circulating pressures:

219.Check for losses. Check both pumps. Do not exceed the annular velocities used during drilling. If hole starts packing off or the hanger starts to plug, cut pump strokes immediately to avoid fracturing the formation. 498.Hook loads while reciprocating are recorded (difference between up and down drag values are monitored for indication of pipe sticking). 499.Reciprocating with casing should be done approx. 2m above the casing head spool. 500.Circulating pressures at intended displacement speeds are recorded. 501.Mud properties are to be checked once again. 502.Do not cement until: 220.Gas readings are no more than the average background reading while drilling. 221.Minimal cuttings/solids are coming over the shakers. 222.Hole conditions are in a stable and satisfactory condition. 503.Stab-in procedures for stinger cementations. 504.Check condition of all four 'o' rings on stab-in tool. Have spare set on site. 505.Make up stab-in tool drillpipe prior to running casing. With shoe track in slips, P/U stabin tool and stab-in and confirm circulation. 506.Install a bow centraliser in the middle of the first drillpipe joint above the stab-in tool. 507.If tool does not stab-in, slowly rotate string with chain tongs. 508.After stab-in, check drillpipe-casing annulus for possible leakage of stab-in seals. If so, pull out the drillpipe and check the condition of the 'o' rings, and replace/repair if necessary.

509.Casing Cement 510.General 511.Ensure that correct type and quantity of cement and additives are on site, include dead tank volumes in calculations. 512.Have compatible defoamer on site. 513.Ensure cement and water samples from the rig have been tested and approved. 514.Check that cement slurry thickening time was measured at bottom hole static temperature less bottomhole circulating temperature. Check and report temperature recorded during wireline logging. 515.Care should be taken if only MWD temperature figures are available. MWD temperatures can be considerable higher than static due to pumping and drilling friction. 516.Thickening time to 40 BC should be +/- 1 hour greater than estimated mixing + displacement time. Thickening times given by the laboratory are only valid for an uninterrupted movement/pumping of the slurry. Any stoppages after mixing has started will reduce final thickening times. Laboratory tests have shown that thickening time can be reduced from over 6 hours to 2.5 hours when movement was stopped after 1.75 hours of simulated slurry pumping. 517.Pressurised balance as well as contractor densiometer have been calibrated.

518.Abnormally high or low air temperatures will effect job execution. 519.Ensure mud pits and lines for mix water and spaces have been cleaned (dedicated mix water tanks should be used if possible). 520.Enough storage is available on surface for displaced fluids. 521.Ensure enough fluid is held on surface if losses are anticipated. 522.Check the cementer’s hook-up. Pressure test and flush the lines. 523.Check rig pump efficiency (check fluid-ends of pumps). 524.Where possible, the cementing head will be a quick latch type that can be loaded with two plugs (i.e., no part of the head has to be broken out to install a second plug). 525.Ensure that the correct plugs are installed in the cementing head in the correct order. 526.Ensure that cementing head has a 'plug away' indicator. 527.Hole is circulated clean. Record pressures at 1/3 and 2/3 of maximum planned circulating rate. 528.While circulating, the annular velocity is to be limited such that the ECD at the previous casing shoe is no more than the leak-off pressure. 529.Do not attempt to cement until the well is completely static. 530.Be sure the hydrostatic head reduction caused by the spacer will not allow the well to flow. 531.Check displacement volume, pump strokes and pumping times: 223.at which the displacement rate should be reduced prior to bumping the plug 224.for cement to reach shoe 225.for equalisation point 226.displacement volume 227.expected pressure differential prior to bumping plug. 532.Use rig pumps for displacement during casing cementations, and cement pumps for displacement of liners and stinger cementations. 533.Rig up lines so that job can be completed without breaking/making up lines. 534.Never bump plugs with the casing suspended in the slips. 535.Record all mixing, bumping, displacing, opening/closing MSC collars, etc., on charts. Install a high-quality pressure gauge on cement head. 536.Hold pre-cementing meeting. 537.Does the spacer require pre-hydration time. 538.Prepare mix water 2-4 hours before job. 539.Ensure side outlet valves on CHS/CMS are fully open and that returns are routed back to the flowline. 540.Take slurry samples during mixing and pumping. 541.Excess cement volumes

26" Hole, 20" Casing

-

Theoretical volume + 100% excess

-

24" Hole, 18.788" Casing

-

17 1/2" Hole, 133/8" Casing

Calliper volume + 50% excess Stinger cementation, Theoretical volume +150% excess

Theoretical volume + 100% excess Calliper volume + 50% excess Stinger cementation, Theoretical volume +150% excess -

Theoretical volume + 100% excess Calliper volume + 50% excess Theoretical top of cement should be a minimum of 200m BELOW mud-line for offshore operations.

16" Hole, 133/8" Casing

-

Theoretical volume + 100% excess Calliper volume + 50% excess Theoretical top of cement should be a minimum of 200m BELOW mud-line for offshore operations.

121/4" Hole, 95/8" Casing

-

Theoretical volume + 30% excess Calliper volume + 20% excess

83/8" Hole, 7" Casing

-

Theoretical volume + 30% excess Calliper volume + 20% excess

542.Where no calliper log is available a cylindrical shaped hole should be assumed. Theoretical hole volume is to be based on the bit size used to drill the section. 543.The 4 arm calliper log reading should be used where available. 544.When cementing into the previous casing shoe, the theoretical top of cement should be at least 250m above the previous shoe. 545.Multistage cementations: theoretical top of cement is job dependent. Care should be taken to ensure that the first stage theoretical top is NOT above the multistage collar. 546.Casing cementing spacers 547.Should be the same type of water as that used in the cement mix water. 548.Ensure enough spacer is used to stop rapid setting of cement with salt muds (i.e., KMg). 549.When cementing across salt section use a NaCl saturated brine spacer instead of a fresh water spacer. 550.A minimum of 4 minutes of spacer/well bore contact is advised (10 minutes contact time should be programmed). 551.The reduction in hydrostatic head due to the spacers must be checked. If the reduction in hydrostatic head is too great then a weighted spacer must be used. 552.A minimum displacement rate of 1.3m/second = 78m/minute is recommended. If for operational reasons this cannot be achieved, spacer volumes should be as large as possible.

553.Since turbulent flow cannot be achieved in 26”/24" and 17 ½”/16" holes a viscous spacer should be used to ensure good mud displacement. If the hole is washed out consider using more spacer volume to attain a height of around 150m. 554.Scavenger slurries with an annular height of 150m are to be pumped in front of the main slurry. The weight of the scavenger is to be half-way between the mud S.D. and the main slurry S.D. The maximum scavenger density with class 'G' cement is 1.6sg. Scavenger slurry volumes are not to be taken into account when making Top Of Cement (TOC)/volume calculations. 555.The use of scavenger slurries with K/Mg muds is not recommended. A weighted spacer should be used. 556.Weight of spacers If S.D. mud < 1.35 unweighted spacers can be used. If S.D. mud > 1.35 then in addition to the water spacer, a viscous, weighted spacer (XC polymer/barite’s or similar service company spacer) must be pumped between the mud and water spacer(s). The S.D. of this viscous spacer should be greater than the S.D. of the mud being displaced. 557.Always calculate loss of hydrostatic head. In the case of unacceptable loss of hydrostatic head use weighted spacers. 558.Surface/stab-in cementation 559.A latch down drillpipe wiper plug is to be used to displace the cement slurry. 560.After stab-in, circulate bottoms up. Check S.D., viscosity, and yield point of the mud. 561.See 11.4.2 for recommended excess cement volumes. 562.Pressure test cement lines. 563.Pump spacer. 564.For surface casing cementation. It is advisable that 2 x 1.66" tubings are run and circulated clean before the cement job proceeds. This can be accomplished while circulating the casing, however, sufficient time has to be allowed for this procedure (possibly more than 2 hours). Run the tubing to 10m below sea bed or +/- 5m below MLS. These tubing strings can be used to flush the casing-conductor annulus, or perform a top fill job if necessary. Pumping should continue until cement returns are seen at surface, total losses occur, or until surface cement reserves in silos are reduced to 10 tons (for top fill cementation). If possible, as soon as the spacer is seen in the returns, the density of the slurry can be increased to tail-in. This is to be within the guidelines as specified in the cementing programme. At least 100% excess should be available on site. This is to be discussed prior to job commencement. Drop pumpdown plug, displace with spacers as specified in section 11.4.3 or in the cementing programme, and enough mud to land plug. Test plug landed by applying 50bar above differential pressure. Bleed off pressure and check for backflow.

If no backflow pressure up to casing test pressure (80% burst strength) and hold for 15 minutes. POOH cementing string. Circulate down the 1.66" tubing and check if returns are cement contaminated. If positive, circulate clean and POOH. If no cement contaminated returns are present then continue RIH with 1.66" tubing to base of conductor, HUD (hold up depth) and carry out top-fill cementation. Mix and pump sufficient cement into the annulus to fill to +/- 10m below MLS or sea bed. Pull back to 10m below sea bed and circulate clean. POOH. 565.Single-stage cementing of casing 566.Use double cement plug head. 567.Circulate. 568.Pump spacers drop bottom plug then pump scavenger slurry. 569.Mix and pump cement as per programme. Check weight regularly, with pressurised mud balance. 570.Collect slurry samples during mixing and label clearly. 571.Release the top plug. Check flag (Rig Superintendent to witness). Pump tail spacers as required and displace cement, using rig pumps. Pump at the maximum pump rate possible until catch-up with the cement column occurs. 572.Once the displacement fluid has caught up to slurry check for losses. 573.Once the displacement fluid has caught up to slurry pump at the rate established in the circulation test or at a rate limited by the ECD of the previous casing shoe. 574.Laminar flow should be avoided. 575.In the majority of cementations, maximum mud displacement will be achieved by pumping a thin slurry at the highest annular velocity permitted by the strength of the weakest formation. As a guide, annular velocities of 75m/minute will assist good mud displacement. If turbulent velocities cannot be achieved due to severe losses, reduce pumping rate until losses drip to an acceptable level. Unless the cementation has been fully engineered in advance (long setting times) for plug flow, the general principal should be to always pump as fast as possible. 576.Casing should be reciprocated during cementation and displacement if hole conditions allow. 577.Thickening times assume that the cement is moving. If pumping stops the cement will gel and shorten the thickening time. 578.Slow down pumping rate before calculated plug bump. Record the differential pressure before bump. Calculate and record pump efficiency. 579.After plug bumps increase pressure to 50bar above differential pressure. Bleed off and check for backflow (and backflow volume). Land casing if not previously done. Pressure test casing against plugs for 15 minutes (test pressure is indicated in well programme). 580.If the plug does not bump according to the calculated volume (assuming an expected pump efficiency, then over-displace by a maximum of half the shoe track volume. If plug

still does not bump then STOP, bleed off and check for backflow. Land casing if not previously done. If plug has not bumped then casing will have to be pressure tested once cement is hard prior to nippling down. 581.If the plug is bumped and there is no backflow (floating equipment is working) then start nippling down BOP etc. If hydrocarbons have been encountered, then Wait On Cement (WOC) prior to lifting BOP's. 582.If there is backflow (floating equipment leaking), then pump back the amount of fluid returned, and wait until cement is hard. Heat will cause a pressure build-up as the cement hardens, so it will be necessary to bleed off pressure while W.O.C. 583.All plugs have a finite pressure rating. The casing test pressure shall be lower than the maximum ratings of the plugs. Ensure test pressures do not exceed the plug pressure rating. 584.It is permissible to count pump strokes but tank volumes should always be measured, provided sufficient tank space exists. 585.Multiple stage cementing Casing tongs should only be used on the upper 12cm or the lower 12cm of the multiple stage cementing collar. Casing tongs should not be used on multiple-stage inflatable or mechanical packer cementing collars. 586.Free fall plug sets (BOMB) After running casing to setting depth, proceed as follows: 587.Circulate. 588.Pump 80% of spacer. 589.Drop By-Pass Plug (BPP, lands on top of by-pass baffle directly above the float collar) and pump remainder of spacer. 590.Install Shut-Off Plug in plug container. 591.Mix and pump cement. Check for weight regularly. Take samples. 592.Displace with mud, reducing pump rate to 100l/min maximum just prior to bumping the SOP on the shut-off baffle (installed 1 joint above the float collar and by-pass baffle). 593.Pressure up to 50bar above differential pressure. Bleed off and check floats, monitor volume returned. 594.Pressure test 1st stage. 595.Maximum recommended test pressures above DIFFERENTIAL against plugs before cement is set: 133/8" casing 5

70bar

9 /8" casing

70bar

7" casing

70bar.

This also applies for shut-off baffles for 95/8" BDS and 7" VAM which are furnished in a baffle adapter.

596.Record how much fluid is required to reach test pressure. Hold pressure for 15 minutes and then bleed off slowly while measuring returns. 597.Drop MSC opening bomb and load MSC closing plug. 598.Do not attempt to surge the opening bomb with pump. Dropping speed of bomb is approximately: 133/8" casing, mud SD 1.2, 70 sec MF = 45m/min 95/8" casing,

mud SD 1.2, 70 sec MF = 67m/min

7" casing,

mud SD 1.2, 70 sec MF = 95m/min.

599.Open MSC by building up to pressure specified in Table 11.1. 600.Circulate minimum annulus contents plus 20%., dump any cement contaminated returns from 1st stage. Check gas readings. 601.If W.O.C., circulate every hour for 10min. with 500l/min. 602.Before cementing second stage ensure that the well is static, then proceed as follows: Pump spacer. Mix and pump cement. Check slurry weight periodically. Take samples. Drop closing plug and displace using rig pump. Close MSC with a minimum pump rate of 1 200l/min. Build up to the closing pressure specified in Table 11.1 and hold for about 5min, to allow time for tool to close. Bleed off to check that MSC is closed. During bumping the plug and closing the MSC, keep pump strokes constant as pressure rises until the closing pressure is reached.

Table 421.1 MSC collar opening and closing pressure Casing Size 133/8" 95/8" 7"

Opening Press 55bar 70bar 65bar

Closing Press 50bar 45bar 50bar

603.Pressure test 2nd stage. Maximum test pressure against plug is: 133/8" casing: 150bar 95/8" casing: 200bar 7" casing: 250bar 604.Hold pressure for 15 minutes and then bleed off quickly while measuring returns. 605.Displacement type plug set After reaching casing depth, proceed as follows:

606.Circulate. 607.Do not attempt to cement until the well is completely static. 608.Pump 80% of spacer. Drop bottom By Pass Plug (BPP), pump remainder of spacer. 609.Mix and pump cement slurry. Check weight periodically. Take slurry samples. 610.Drop top BPP. Install opening plug in container head (if possible). 611.Use cement unit to pump theoretical volume between float and MSC collar. Measure this volume carefully using cement unit tanks. 612.Drop opening plug and load MSC closing plug. Displace using rig pump until plug lands on MSC sleeve, build up to opening pressure specified. Circulate to clear any cement that may have reached the MSC. 613.If WOC, circulate every hour for 10 minutes with 500l/min. 614.Before cementing second stage ensure that the well is static, then proceed as follows: Pump spacer. Mix and pump cement. Check slurry weight periodically. Take samples. Drop closing plug and displace using rig pump. Close MSC with a minimum pump rate of 1 200l/min. Build up to the closing pressure specified in Table 11.1 and hold for about 5 minutes to allow time for tool to close. Bleed off to check that MSC is closed. During bumping the plug and closing the MSC, keep pump strokes constant as pressure rises until the closing pressure is reached. 615.Pressure test 2nd stage. Maximum differential test pressure plug is: 133/8" casing: 150bar 95/8" casing: 200bar 7" casing: 250bar 616.Hold pressure for 15 minutes and then bleed off while measuring returns. 617.Multiple-stage cementing displacement 618.It is not acceptable to monitor the volume pumped with a 'barrel counter'. 619.Since pipe movement is not possible after first stage cement job, it is important that turbulent flow displacement be achieved in the second stage cement slurry displacement if possible. 620.Multiple-stage packer cementing 621.Multiple-stage inflatable packer cementing Multiple-stage inflatable packer cementing (MSIPC) is virtually identical to normal multistage cementing, the only difference being that the opening of the cementing ports (and inflating the packer) occurs in two stages. Inflation of the packer occurs after the completion of displacement of the first stage cement when the opening plug (free-fall of displacement type) lands on the opening plug seat. Applying pressure (the packer port

opening pressure) pushes the plug seat down and opens the ports into the packer. Further pressure, in 15bar increments, inflates the packer with the pressuring fluid (can be mud, spacer or cement). Further, addition of pressure (the secondary opening pressure) pushes a secondary sleeve down, opening the cementing ports for the second stage. As the secondary sleeve moves down, a check valve closes, trapping full inflation pressure inside the packer element. Upon completion of cementation and displacement, the tool is closed when the closing (displacement) plug lands on the closing sleeve seat and the required differential pressure applied. The MSICP can hold pressure form above or below. Check with the supplier as to the maximum differential pressure which can be sustained. Free fall or displacement type plug sets can be used and the running procedures are identical to those laid out in sections 11.4.7 and 11.4.8, the only difference being the application of the MSC opening pressure in two stages. Pressures required to open and close the ports are given in Table 11.2. Check the maximum possible packer setting size versus the inner diameter of the casing to ensure the MSIPC is used within its design limits. Table 421.2 MSIPC opening and closing pressures Casing Size 7" 95/8" 133/8"

Packer Port Opening Press 70bar 70bar 50bar

Secondary Opening Press 100bar* 105bar* 90bar*

Closing Press 50bar 45bar 50bar

* The pressure marked with an asterisk is the pressure applied internally across the secondary sleeve to open the outer ports. If there is a differential pressure across the sleeve due to a heavier fluid in the annulus versus the casing fluid, the pressure required to open the outer ports will be the SECONDARY OPENING PRESSURE PLUS THE DIFFERENTIAL PRESSURE. 622.Multiple Stage Mechanical Packer Cementing Multiple stage mechanical packer cementing (MSMPC) is virtually identical to normal multi-stage cementing, the only difference being that the opening of the cementing ports (and setting the packer) occurs in two stages. Setting of the packer occurs after the completion of displacement of the first stage cement when the opening plug (free fall or displacement type) lands on the opening plug seat. Applying pressure (the packer port opening pressure) pushes the plug seat down and opens the ports into the annular area behind the setting sleeve. Further pressure forces the setting sleeve down, compressing the packer element. Further addition of pressure (the secondary opening pressure) pushes a secondary sleeve down opening the cementing ports for the second stage. As the secondary sleeve moves down, internal locking rings retain the packer element in the set position. Upon completion of cementation and displacement, the tool is closed when the closing plug lands on the closing sleeve seat, and the required differential pressure applied.

Maximum differential pressure across the packer is 70bar. Due to the packer design (cup type), this pressure can only be held from above. As clearance between maximum and minimum hole size in which packer can be properly set is relatively small, it is not recommended to set the MSMPC in open hole. Free fall or displacement type plug sets can be used and the running procedures are identical to those laid out in sections 11.4.7 and 11.4.8, the only difference being the application of the MSC opening pressure in two stages. Pressures required to open and close the ports are given in Table 11.3. Check the maximum possible packer setting size versus the inner diameter of the casing to ensure the MSMPC is used within its design limits.

Table 421.3 MSMPC opening and closing pressures Casing Size 95/8" 133/8"

Packer Port Opening Press 65bar 45bar

Secondary Opening Press 125bar* 95bar*

Closing Press 45bar 45bar

*The pressure marked with an asterisk is the pressure applied internally across the secondary sleeve to open the outer ports. If there is a differential pressure across the sleeve due to a heavier fluid in the annulus versus the casing fluid, the pressure required to open the outer ports will be the SECONDARY OPENING PRESSURE PLUS THE DIFFERENTIAL PRESSURE.

623.Liner Running and cementing 624.General A pre-job meeting is to be held with the supplier’s representative to ensure full agreement of procedures to be followed. Any changes should be confirmed. Changes are to be included in the on-site instructions. Maximum circulation pressure at any stage prior to setting the liner hanger must be less than 2/3 of the hanger setting pressure. Setting pressure is dependent on the size of hanger being run and the type of shear pins installed. Maximum circulating rates (for Baker hanger integrity) See 11.5.3. It is recommended that:

625.The liner lap should be a minimum length of 50 metres. 626.Preferably, the top of the polished bore receptacle (PBR) should be spaced out such that the sealing elements of a tie-back packer will not be within 1 metre of a casing connection. 627.Liners should be set as close to bottom as is practical. 628.Shoe track composition and centraliser placement should be specified in the drilling programme. 629.Rotating Liner 228.Procedures for rotating liners (See 11.5.2). Generally they are identical to those for a non-rotating liner. Where they differ, an additional note has been included.

229.Surface torque while rotating should be limited to the cased hole torque test value (See 11.5.2) plus 80% of the make-up torque of the liner thread connection. NOTE: The maximum allowable surface torque shall be 80% of the torsion strength of the weakest component of the running string. 630.Prior to running the liner Prior to running the liner:

631.A wiper trip should be made if hole conditions require. Use the check trip assembly. 632.Prior to pulling out of the hole circulate clean, pump a viscous pill and ensure that; 230.continuous background gas is less than the average background gas while drilling. 231.yield point and gel values have been reduced to the minimum practical value, confirm with the Rig Superintendent (Y.P. preferably less than 10lbs/100ft2). 232.minimal cuttings/solids are coming over the shakers. 233.hole conditions are satisfactory. 633.Rotating Liner 234.Prior to pulling out to run the liner, perform a rotational torque test with bit on bottom and with the bit in the last casing shoe. Perform the test both with and without circulation. Record rotating torque for each case in the daily drilling report.

Table 421.4 Example of rotating torque record RPM 10 10 20 20

At Last Casing Shoe SPM TORQUE Nm OR Ftlbs 0 0

At Bottom SPM

TORQUE Nm OR Ftlbs

0 0

634.Cased Hole Torque Test Value shall be the value obtained during the torque test performed at the previous casing shoe when pulling out to run the linear. 635.Strap out of the hole on the last trip if there is a significant difference between logger’s and driller’s depths. 636.Drop a drillpipe drift on last trip out of hole. The drift used shall allow circulation through the drillstring. 235.Ensure that the drift is retrieved. 236.Ensure all components to be used in the liner running/handling string are also drifted. Check connections for debris, etc. 237.31/2" running string : 21/4" DP drift 238.5" running string : 21/2" DP drift 637.Check all connections of float shoe, collar, plug landing collar, liner hanger, tie-back assembly, etc. 638.Calculate surge and swab pressures (using Drill-Calc).

639.Ensure a circulating head for each casing and drillpipe connection is available on the drillfloor. Also ensure that a crossover from drillpipe to liner is available. 640.Ensure a Co-flexip cementing hose, or approximately 10 metres of Chiksan line (already made up), is available on the rig floor. 641.The following operations should be performed at the most opportune time prior to running the liner: 239.Top Drive: Make up plug dropping head assembly onto a (pup) joint and lay down a catwalk. 240.Rotary Table, with rotating liner: Make up plug, dropping head assembly onto cementing kelly and lay down on catwalk. 642.Running the liner 643.Make up the shoetrack. Check that the floating equipment is functioning properly. 644.Make up and run in hole with the liner, maximum running speed; 60 seconds per stand of drillpipe. 645.The fill-up hose, or casing packer, should be used between connections. Stop and completely fill the string every 5 to 10 joints, as required. 646.Pup joints should be positioned as per programme. 647.Make up liner hanger assembly and running tool, ensuring that the block is unlocked and that the string does not rotate while running in hole. 648.Centralisers should be installed as specified in the drilling programme. 649.Install the kelly/top drive and break circulation. Check for leaks between running tools and liner top. Record string weights up, down and neutral. 650.Install the drillpipe wiper to prevent anything falling down the hole. 651.Maximum circulation rates shall be confirmed with the equipment supplier prior to commencing circulation. 652.The following rates are only a guide: 7" liner

: 1 000ltr/min

7" liner with integral tie back packer

:

750ltr/min

5" liner

:

700ltr/min

:

500ltr/min

1

4 /2" liner

NOTE: Maximum circulation pressure is to be less than 2/3 of the hanger setting pressure, to avoid premature setting. 653.Rotating Liner 241.Perform surface rotational torque check. 654.Continue running liner on drillpipe filling every stand. Maximum running speed; 60 seconds per stand of drillpipe. 655.Ensure that no left-hand rotation of the string occurs while making up or running in the liner, as this may activate the emergency release of the hanger running tool.

656.Break circulation at the last casing shoe, maximum circulation pressure to be no more than 2/3 of the liner setting pressure. 657.Rotating Liner 242.While circulating, perform a rotating torque test at 10 to 12rpm. Record results in daily drilling report and in the cementing report. 658.Rotating Liner 243.The running tool allows the liner to be washed through open hole. See 11.5.6 for procedures relating to the washing of rotating liners through tight hole. 659.Space out string so that the liner shoe is at the required depth and: 244.There are no drillpipe tool joints positioned in the BOP. 245.The plug dropping head is approximately 1 metre above the rotary table. 246.Liner shoe should be set as close to bottom as is practical. 660.Circulate a minimum of the last joint down. Maximum circulation pressure to be no more than 2/3 of the hanger setting pressure. Maximum circulating rates as mentioned above. NOTE: If the pressure required to break circulation is greater than 2/3 of the hanger setting pressure, ensure the liner is at the required setting depth prior to exceeding it. 661.Perform a circulating test. As a basis use the annular velocity while drilling. If no losses are observed, increase the pump rate until the desired pump rate is reached. If losses are observed, decrease the pump rate until losses stop. Record the test results in the daily drilling report and in the cementing report. 662.Circulate 120% string and annulus contents; if required circulate a hi-vis pill. Wherever possible reciprocate the string slowly, for as long as possible. 663.Rotating Liner 247.While circulating, start rotating at 10 to 12rpm and compare with the torque recorded before pulling out to run the liner and when the liner was at the previous casing shoe. 248.Surface torque while rotating should be limited to the cased hole torque test value (See 11.5.2) plus 80% of the makeup torque of the liner thread connection. NOTE: The maximum allowable surface torque shall be 80% of the torsion strength of the weakest component of the running string.

664.Record string weights up, down and neutral. 665.Setting the liner hanger (Baker Flex-Lock) 666.Make up surface lines and pressure test to a minimum of 200bar. 667.Position liner at the required setting depth. 668.Drop ball and slowly chase with 150ltr/min until ball lands. If the ball fails to seat initially, surge the pumps and/or reciprocate the drillpipe to assist. 669.Ball for 7" liner (2 plug system) Ball for 7" liner (4 plug system) Ball for 41/2" and 5" liner

= 13/4" diameter = 1 /2" diameter = 11/2" diameter. 1

670.Increase pump pressure to the required setting pressure and set the hanger. Keep pressure on and lower the string to ensure the hanger is set, slack off liner weight plus an additional 8 to 10 tonnes. NOTE: Hanger setting pressure is dependent on the size of hanger and the type of shear pins installed. 671.Once the hanger is set 672.Non-Rotating Liner 249.Increase the pressure to above the pre-set shear value of the running tool. The required pressure will depend on the number and type of shear pins installed. Maximum allowable pressure is 80% of the ball seat shear-out pressure, until the setting tool has been checked for release. Repeat the release procedure if necessary. 250.Pick up 1/2 a metre to ensure the running tool has been released from the hanger. 251.Once set, shear out the ball seat with approximately 180bar. 673.Rotating Liner 674.Check that the string will rotate, then stop rotation and increase the pressure to above the shear value of the running tool. The required pressure will depend on the number and type of shear pins installed. Maximum pressure is 80% of the ball seat shear-out pressure until the setting tool has been checked for release, repeat release procedure if necessary. 675.Pick up 1/2 a metre to ensure that the running tool has been released form the hanger. 676.Once set, shear out the ball seat with approximately 180bar. 677.Perform cased hole torque test 1/2 a metre above the liner. Rotate the drillstring slowly at 10 to 12rpm and record the torque. While rotating slowly set down 10 to 15 tonnes on the hanger and establish circulation. The initial torque may be high, but should reduce once the entire liner string is turning. 678.Surface torque while rotating should be limited to the cased hole torque test value (See 11.5.2) plus 80% of the makeup torque of the liner thread connection. NOTE: The maximum allowable surface torque shall be 80% of the torsion strength of the weakest component of the running string. 679.If the Hanger Does Not Set 252.Increase the pressure in stages of 15bar, and slack off as mentioned above. Allow time for the hanger slips to fully set prior to increasing to the next increment. If 80% of the running tool shear-out pressure is reached, bleed off pressure to zero and repeat.

680.If the Hanger Still Does Not Set 253.Use the emergency release system of the running tool. Set string on bottom and apply left-hand torque to shear the set screws and release from the setting sleeve. The emergency release will only work if the total liner weight has been removed from the setting tool. The torque required depends on the number and type of shear pins installed in the setting tool. 681.If the Running Tool Does Not Hydraulically Release From the Hanger 254.Use the emergency release system of the running tool as mentioned above.

682.Rotating Liners 255.If the string is rotating freely and the hanger has been set, it will be necessary to unset the hanger and sit the string on the bottom before applying left-hand torque. NOTE: The setting tool will only release if the total liner weight has been released from the tool. Hole conditions may require movement of the drillpipe to "work" the set-down weight to the setting tool. 683.After Setting the Hanger and Releasing the Running Tool 684.Circulate until ready to cement, and ensure that the following conditions exist prior to cementing: 256.gas readings are less than the average background gas while drilling. 257.yield point and gel values have been reduced to the minimum practical value, confirm with the Rig Superintendent (Y.P. preferably less than 10lbs/100ft2). 258.Minimal solids are coming over the shakers. 259.Hole conditions are satisfactory. 685.Rotating Liner 260.Maintain 10 to 15 tonnes weight on the hanger while circulating. 686.Change over lines for cementing. 687.Cement as per instructions, See 11.6, Liner Cementation. 688.After cementing, check to ensure running tool is free by picking up approximately 5 metres and then running in 1 metre. If no change in weight is observed then the tool is free and the trip out can be continued. 689.Working rotating liners through tight hole sections 690.Ensure that the circulating pressure does not exceed 2/3 of the liner hanger setting pressure. 691.When rotation is required, proceed with the following steps: Pick up pipe. Start circulation and check up, down and neutral weight of string. When exact down weight is known, start rotating slowly. Watch pressure carefully. When rotation and circulation are stabilised, slowly lower pipe into the tight spot. Ensure circulating pressure remains below 2/3 of the hanger setting pressure. A maximum set down weight of 5 tonnes is to be observed. Maximum allowable torque shall be 80% of the torsion strength of the weakest component of the running string, or 80% of the liner connection strength, or whichever is weakest. If 5 tonnes of weight is reached, work pipe up and down through the tight spot.

692.Liner Cementation 693.General 694.For liner cementations use properly checked water.

695.From the logs obtain the bottom hole static temperature. Check that the cement recipe was designed and tested for a bottom hole static temperature which corresponds to the bottomhole static temperature from logs to within 5°C. 696.The reduction in hydrostatic head due to the spacer must be checked. If the reduction in hydrostatic head is too large then a weighted spacer must be used. 697.Calculate the maximum circulating rate which can be theoretically achieved without fracturing the previous casing shoe or the open hole formation. 698.Ensure that an active tank is available to receive returns during cementing. 699.Use cement contractor’s displacement tanks for displacing cement. 700.A batch tank should be used to mix cement wherever possible. 701.Minimum amount of cement to be mixed in the batch mix tank is 6m3 of slurry. 702.Always measure slurry weight with a pressurised mud balance. 703.Make a volume pumped versus pressure plot to show: 261.shear liner wiper plug 262.when spacers reach shoe 263.when cement reaches shoe 264.when cement reaches liner lap 265.when cement reaches top of liner lap 266.when plug bumps. 704.Thickening times given by the laboratory are only valid for an uninterrupted movement/pumping of the slurry. Any stoppages after mixing has started will reduce final thickening times. Laboratory tests have shown that thickening time can be reduced from over 6 hours to 2.5 hours when movement is stopped after 1.75 hours of simulated slurry pumping. 705.Cement volumes Cement volumes for all liners sizes should be based upon the following:

706.openhole calliper volume* + liner lap volume + 100 to 150m of cased hole volume above the liner hanger. NOTE: Each liner cementation should be considered on its own merits. * Based on field experience a percentage excess may be required. 707.Pre-flush spacers for liners cementations. 708.For holes drilled with water based mud. Table 421.5 Pre-flush spacers for liner cementations (Water based mud) OH (in) 83/8

Liners (in) 7

5/8

41/2

Spacer Ahead Volume (m3) Height (m) ** 2.0 MW* 150 2.0 SC 150 1.2 MW 150 1.2 SC 150

Spacer Behind Volume (m3) Height (m) ** 4.0 MW 300 1.5 MW

300

* If SD mud > 1.35 unweighed spacers can be used. If mud > 1.35 then in addition to the water spacer, a viscous weighted spacer (XC polymer, barites) must be pumped between the mud and water spacer(s). The S.D. of this viscous spacer should be greater then the S.D. of the mud being displaced. ** Based on volume specified inside, gauge hole to casing annulus. 709.If KMg mud was used to drill the hole section pump a viscous (fresh) water spacer after the spacer behind. The viscous spacer should have a volume of liner contents plus the volume of 200m drillpipe. This will prevent any risk of flash setting should the mud and cement come into contact when stinging out of liner. Check the bottomhole pressure and if underbalanced, then pump a weighted spacer. 710.With less critical cementations water can be considered for use as "spacer behind" rather than mixwater. 711.For holes drilled with oil based mud Table 421.6 Pre-flush spacers for liner cementations (VCM) OH (in) 83/8

Liners (in) 7

57/8

41/2

Spacer Ahead Volume (m3) Height (m) ** 2.0 BO 150 2.0 SC 150 1.2 BO 125 1.2 SC 150

Spacer Behind Volume (m3) Height (m) ** 2.0 MW 100 2.0 BO 100 1.0 MW 120 1.0 BO 120

** Based on volume specified inside gauge hole to casing annulus. 712.Scavenger slurry displacement The objective of the scavenger slurry is to remove the filter cake. To do this effectively it must be pumped in turbulent flow. An annular velocity of 100m/min is recommended for good mud displacement and should be of sufficient volume to provide a contact time of 10 minutes.

713.The slurry recipe will be advised. 714.Main Slurry Displacement Four-Plug System (Baker) 715.Pump pre-flush/spacers as specified in Tables 11.5 and 11.6. 716.Close the bottom valve on the plug dropping head. Wind out the plug holding spindle (if no flag is used hold 40bar against the top valve) and open the top valve, check flag to ensure plug has left the head. 717.Close top and bottom valves on the plug dropping head, wind in the plug holding spindle and reset the indicator flag. Remove the cap from the plug dropping head and load the upper pump down plug, refit the cap and open the bottom valve (this step is only necessary if using a single plug head). 718.Pump the pre-mixed main slurry from the batch tank into the well. When using large slurry volumes, or if the drillpipe-annulus pressure differential is great (+/- 50bar), back pressure must be applied at the choke to control the rate of fall of the cement slurry (control level of back pressure to avoid formation break down).

When the capacity of the drillpipe has been pumped, the lower pump down plug will latch into the lower liner wiper plug. Slow down to 250ltrs/min +/- 1m3 before this point. A pressure increase of +/- 150bar will shear the liner wiper plug free. Complete pumping cement. With this hanger running design the slick stinger is spaced out into the liner wiper plug holding system. If it is necessary to exceed 150bar above the circulation pressure to shear the plug, bleed off pressure, pick up the string +/- 50cm and pressure up again. This will expose the plug and allow the pressure to act over a greater area. Shear the plug then set back down and complete pumping cement. Do not apply more than 150bar plus circulating pressure to the system. 719.Close the bottom valve on the plug dropping head and flush lines if necessary. Check the indicator flag has been reset. Wind out the plug holding spindle (if no flag sub is used, hold 40bar against the top valve) and open the top valve, checking flag to ensure the plug has left the head. 720.Pump post flush and displace cement. The maximum displacement rate is generally the fastest possible rate at which no losses occur. The circulation test data can be entered into in-house computer programmes to help predict maximum circulation rates with cement slurry. Refer to the cementing program. When the capacity of the drillpipe has been pumped, the upper pump down plug will latch into the upper liner wiper plug. Slow down to 250ltrs/min +/- 1m3 before this point. A pressure increase of +/- 150bar will shear the liner wiper plug free. Complete displacement. With this hanger running design the slick stinger so that it is spaced out into the liner wiper plug holding system. If it is necessary to exceed 150bar above circulation pressure to shear the plug, bleed off pressure, pick up the string +/- 50cm and pressure up again. This will expose the plug more, allowing the pressure to act over a greater area. Shear the plug, then set back down and continue the displacement. Do not apply more than 150bar plus circulating pressure to the system. 721.If no shear is observed, pump 2m3 past the expected shear point and return to original displacement rate. Use the theoretical displacement volume only (do not over displace by more than half the shoe track volume). 722.Reduce rate +/- 0.5m3 before expected plug bump. Bump plug with +/- 50bar above the calculated static differential pressure and hold for 5 minutes. 723.Bleed off and check for backflow. 724.Apply +/- 50bar to the liner and pick up on the drillstring. When the slick stinger comes out of the flapper valve "O" ring (approximately 4m), the pressure will drop, although there may still be some pressure if sufficient excess cement is above the liner. 725.Wait for the cement to equalise between drillpipe and annulus (to reduce contamination) and POOH. 726.Circulate out excess cement if programmed. Reciprocate pipe while circulating. Two Plug System (Baker)

727.Pump pre-flush/spacers as specified in Tables 11.5 and 11.6.

728.Pump the pre-mixed main slurry from the batch tank into the well. 267.When using large slurry volumes or if the drill pipe-annulus pressure differential is great (+/- 50bar), back pressure must be applied at the choke to control the rate of fall of the cement slurry (control the level of back pressure to avoid formation break down). 729.Close the bottom valve on the plug dropping head and flush lines if necessary. Ensure the indicator flag has been set. Wind out the plug holding spindle (if no flag sub is used hold 40bar against the top valve) and open the top valve, checking flag to ensure the plug has left the head. 730.Pump post flush and displace cement. 268.The maximum displacement rate that can be achieved without losses is generally considered desirable. Refer to the cementing program. 269.When the capacity of the drillpipe has been pumped, the upper pump down plug will latch into the upper liner wiper plug. Slow down to 250ltrs/min +/-1m3 before this point. A pressure increase of +/- 150bar will shear the liner wiper plug free. Complete displacement. 270.With this hanger running design the slick stinger is spaced out into the liner wiper plug holding system. If it is necessary to exceed 150bar above circulation, pressure up again. This will expose the plug more, allowing the pressure to act over a greater area. Shear the plug, then set back down and continue the displacement. 271.Do not apply more than 150bar plus circulating pressure to the system. 731.If no shear is observed, pump 2m3 past the expected shear point and return to original displacement rate. Use the theoretical displacement volume only (do not over displace by more than half the shoe track volume). 732.Reduce rate +/- 0.5m3 before expected plug bump. Bump plug with +/- 50bar above the calculated static differential pressure and hold for 5min. 733.Bleed off and check for backflow. 734.Apply +/- 50bar to the liner and pick up on the drillstring. When the slick stinger comes out of the flapper valve "O" ring (approximately 4m), the pressure will drop, although there may still be some pressure if sufficient excess cement is above the liner. 735.Wait for the cement to equalise between drillpipe and annulus (to reduce contamination) and POOH. 736.Circulate out excess cement if programmed. Reciprocate pipe while circulating.

737.Squeeze Cementation 738.Applications 739.Supplementing a primary cementation that failed. 740.Elimination of water/gas intrusion. 741.Repairing of casing leaks. 742.Abandoning old perforations or plugging off depleted zones. 743.Curing lost circulation.

744.General 745.Slurry Design 272.Fluid loss control agents ensure that no premature bridging of cement occurs due to dehydration of cement. 273.Friction reducers facilitate good penetration of the slurry. 274.Retarders are necessary for long squeeze jobs, particularly hesitation squeezes. 746.Injectivity test 747.Make an injectivity test prior to spotting the cement slurry. 748.Injectivity of about 0.16cu.m/min is normally required to squeeze off perforations and higher rates for cement bond repairs. 749.Perforations cannot be squeezed off when large losses are being experienced. In such cases losses will have to be reduced. 750.Care must be taken not to block the perforations with L.C.M. so that they will not be able to accept cement. 751.Pressures 752.All surface pressures are to be recorded and immediately related to their bottomhole pressure. 753.It is good practice to hold back pressure on the annulus above the cement retainer. 754.It is important not to exceed the formation fracture pressure. 755.Squeeze methods 756.Bradenhead (No packer) 275.R.I.H. to bottom of perforations. 276.Circulate on bottom. Check well is static. 277.Set "Balance" plug of required volume. 278.P.O.H. until stinger is +/- 100m above theoretical T.O.C. 279.Reverse circulate well clean. 280.Close BOP's on drillpipe. 281.Squeeze via the string. 757.Circulation Squeeze Used on primary cementation repair jobs where circulation cannot be established with one set of perforations to surface. 282.Perforate above top and below bottom of zone to be cemented. 283.R.I.H. with bridge plug on drillpipe. 284.Set bridge plug between perforations. 285.Circulate casing/hole annulus, clean (calculate casing collapse pressure). 286.Unsting from bridge plug and circulate hole clean. Spot a high vis pill. 287.Sting into bridge plug. Circulate/squeeze cement around perforations as per programme. 288.Unsting from bridge plus and pull back to above theoretical T.O.C. and reverse circulate out any cement.

289.If enough cement has been pumped, it is possible to Bradenhead squeeze a volume of cement into top perforations (do not over-displace perforations). 290.If unable to establish circulation, block squeeze lower perforations and Bradenhead top perforations.

758.Block Squeeze 291.Used on long primary cementation repairs where it is difficult to establish proper circulation over the whole section. 292.The repair is split into a number of squeezes through cement retainers with only one set of perforations below. 759.Hesitation squeeze 293.Used to obtain a more uniform fill when squeezing off perforations. 294.Performed in the same way as the Block squeeze except that the squeeze period is split into alternate squeeze and shut-in periods. 295.Different perforations (in the same zone) will have different injectivities. On the first squeeze the perforations with the highest injectivity will accept cement. Further squeezes will begin to fill perforations with less injectivity until the zone becomes plugged-off. Do not initially exceed formation breakdown pressure during squeezing. 296.R.I.H. to bottom of required squeeze zone. 297.Circulate and ensure well is static. 298.Set balanced cement plug as per programme. 299.P.O.H. until stinger is +/- 100m above theoretical T.O.C. 300.Reverse circulate well clean. 301.Close BOP's on drillpipe. 302.Squeeze via string as follows: Increase drillpipe pressure until a leak-off is observed (It is not the intention to fracture the formation or inject the pumping fluid). Hold for a minimum of 5 minutes, or until a leak-off is observed. Repeat pressure build-up and hold phases until 20% of original plug volume remains in the casing, or the maximum allowable surface pressure (to be set by the Rig Manager) has been achieved. Hold 85% of initial leak-off pressure on drillpipe for a minimum two times the tested slurry setting time. While holding back pressure circulate at 0.2m3/min for 2 minutes every half-hour to ensure string remains free. 760.Cement plug setting procedure A cement plug shall be set as a balanced plug. Once the required volume of the cement slurry is in place, the well pressures in annulus and drillpipe string should be zero. This can be obtained by using the proper amounts and weights of spacers and mud. Always realise the reduction of hydrostatic head due to lighter spacers and whilst the cement slurry is setting. Cement plugs can be set via open-ended drillpipe. It is good practice is to use a tubing stinger of at least the same length of the cement plug on the drillpipe string. Smaller cement plugs of 5m3 or less shall be made out of a pre-mixed slurry (pre-mix tank to be available.)

Contents

12. SURVEYING......................................................................................................................ii 12.1 Introduction ................................................................................................................ ii 12.2 Co-ordinate Systems.................................................................................................. ii 12.3 Reference Definitions................................................................................................. ii 12.4 Surveying During Drilling........................................................................................... iv 12.4.1 Surveying tools..................................................................................................v 12.4.2 Survey frequency during drilling........................................................................v 12.4.3 Definitive surveying/verification surveying ....................................................... vi 12.4.4 Survey requirements ....................................................................................... vii 12.4.5 Definitive survey frequency (verification survey) ............................................. vii 12.4.6 Tie-on and overlap surveys ............................................................................. vii 12.5 Survey Instrument Positioning/Running Procedures................................................ vii 12.5.1 Magnetic single and multi-shot........................................................................ vii 12.5.2 Electronic magnetic single-shot ..................................................................... viii 12.5.3 Electronic magnetic multi-shot ....................................................................... viii 12.5.4 Measurement while drilling............................................................................. viii 12.5.5 Gyroscopic tools............................................................................................... ix 12.6 Side track .................................................................................................................. ix 12.7 Collision Monitoring................................................................................................... ix Illustrations

Figure 12.1 Correction for grid and declination....................................................................... iv Tables

Table 12.1 Surveying tools ......................................................................................................v Table 12.2 Survey frequency during drilling............................................................................ vi Table 12.3 Verification survey requirements.......................................................................... vii

761.SURVEYING

762.Introduction This section provides information on the surveying methods and the equipment used in drilling operations. The drilling programme shall highlight the exact wellhead position co-ordinates. Together with the drilling programme a detailed deviation plot shall be issued for directional drilled wells. A qualified directional drilling contractor will be contracted for directional drilling. The survey equipment, together with the adequate directional drilling tools, will be available as rental items.

763.Co-ordinate Systems Offshore exploration applies two positioning systems. These are used for the location of the wellhead, and the trajectory of the borehole. The Transverse Mercator (TM) grid system is used to give the wellhead a position. This system is based on a transverse mercator projection of the earth's surface on a map with a central meridian at 5o East. Further information on this system can be found in the International Association of Drilling Contractors’ report (SPC 17212 Directional Drilling Azimuth Reference Systems). The borehole trajectory is plotted with an orthogonal co-ordinate system with the origin at the wellhead. The X and Y directions are parallel to the corresponding axes of the grid co-ordination system and the Zaxis correspondents to the direction of the earth's gravity field (true vertical). Most surveying tools, however, provide an inclination and an azimuth of the hole for a given alonghole (AH) depth rather than the X, Y, Z co-ordinates. The borehole trajectory in terms of X, Y, Z co-ordinates is computed from the survey data. Many drilling contractors prefer the minimum curvature method.

764.Reference Definitions To ensure consistency in plotting the position and trajectory of a borehole, it is vital that all the personnel involved in the operation use the same reference points; thereby providing the surveying tools with the same starting points every time a further position is plotted. The basis for these reference points is defined in the following paragraphs. The alonghole depth reference point is the original rotary table elevation (ORT) for the borehole. The Mean Sea Level (MSL) can also be used as the reference point for offshore wells. When surveying during a re-entry or after jacking-up a platform, a correction has to be applied to the measured alonghole depth to correct for the difference between the original and the current rotary table elevation. Inclination: The inclination reference point is the true vertical direction, which corresponds to the direction of the earth's gravity field. Declination: The azimuth reference point is the Y-axis pointing to grid North. The azimuth readings of magnetic surveying tools are referenced to Magnetic North (MN) and have to be corrected in two steps for:

765.Magnetic declination. In company operations Magnetic North is West of True North (TN). 766.Convergence of meridians; grid correction. In the grid co-ordinate system Grid North (GN) is West of TN, West of the central meridian, East of TN, and East of the central meridian.

Conventional gyroscopic surveying tools are oriented using a foresight which is measured with reference to GN. No corrections are required if foresight is used to process the survey data. North-seeking gyroscopic surveying tools measure azimuth with reference to TN, therefore the grid correction has to be made. In companies operations magnetic declination from MN to GN and grid correction from TN to GN are defined positive in a clockwise direction. So the GN-azimuth data is obtained from the instrument readings by subtracting the corrections:

767.Magnetic tools: Az (GN) = Az (tool) - declination - grid correction. 768.North seeking tools: Az (GN) = Az (tool) - grid correction. For a visual representation of grid corrections see Figure 12.1. To ensure that it is possible to easily monitor the borehole trajectory, it is vital to define the reference points before commencing work on the drilling programme. It is the responsibility of the Company Representative to check the following:

769.Ensure that the rig is in the correct location and is using the correct slot if positioned over a platform. 770.Check that the wellhead, the target co-ordinates, and all deviation parameters on the well plot are in accordance with the drilling programme. 771.Check that the azimuth reference on the well plot is Grid North (GN). 772.Ensure the following survey reference information is available on board: 303.Longitude and latitude of the wellhead (used for north-seeking gyro tools). 304.The original rotary table elevation (ORT) and the correction values for the current rotary elevation (CRT). 773.That Grid correction is used to convert True North (TN) referenced values into Grid North (GN) referenced values. 774.That magnetic declination is used to convert magnetic azimuth readings into True North referenced values. 775.That, when running a magnetic surveying tool corrected with the magnetic interference algorithm, the dip angle and the total strength of the local earth magnetic field is used as input.

Figure 761.1 Correction for grid and declination NOTE: In operations involving a multiple well plot, ensure all are depth-referenced to the well being drilled using the same datum level.

776.Surveying During Drilling Surveys are required to monitor the borehole trajectory to:

777.Follow the designed borehole course (the plot) and thus reach the target. 778.Avoid collision with other wells. 779.Enable drilling of relief wells. 780.Comply with legislations.

781.Surveying tools A wide variety of surveying tools is available for drilling (listed in Table 12.1). The tools have different azimuth references.

Table 761.1 Surveying tools Tool Codes Survey Tool Description AMWD ANADRILL Measurement While Drilling Tool BGT Borehole Geometry Tool CDR Compensated Dip Reading CMWD Christensen Measurement While Drilling DMWD Datadril Measurement While Drilling EEMS Eastman Electronic Multi-Shot EGMS Eastman Gyro Multi-Shot EGSS Eastman Gyro Single-Shot EMS Eastman Multi-Shot (magnetic) ENST ENSCO Steering Tool ESS Eastman Single-Shot (magnetic) EST Eastman Steering Tool FER Ferranti’s Finds Tool (final version) GCT Schlumberger Guidance Continuous Tool GEMS Gyrodata Electronic Multi-Shot GNRT Gyrodata North Reference Tool HDT High-resolution Dipmeter Tool HMWD Halliburton Geodata MWD PKM Photo Klinometer PST Preussag Steering Tool SDCF Scientific Drilling Control’s FINDER SDEM Scientific Drill, Elect. Magn. Multi-Shot SDGM Scientific Drilling Gyro Multi-Shot SDGS Scientific Drilling Gyro Single-Shot SDMM Scientific Drilling Magnetic Multi-Shot SDST Scientific Drilling Control Steering Tool SEEK Eastman Chr. SEEKER North Seeking Gyro SEMS Sperry Electronic Multi-Shot SGMS Sperry Gyro Multi-Shot SGSS Sperry Gyro Single-Shot SMS Sperry Sun Multi-Shot (magnetic) SMWD Sperry Sun Measurement While Drilling SNG Sperry Sun North Seeking Gyro SPEM Sperry Sun’s Enhanced Magnetic Survey SSS Sperry Sun Single Shot (magnetic) SST Sperry Sun Steering Tool TCO Totco TMWD Teleco Measurement While Drilling *Azimuth References 1. True North 3. Magnetic North 2. Grid North 4. Optional (to be specified by the user)

Azimuth References* 3 4 3 3 3 3 2 2 4 3 3 3 2 2 3 2 4 3 3 3 2 3 1 2 2 3 2 3 4 2 3 3 2 2 3 3 4 3

782.Survey frequency during drilling Surveying at regular intervals is dependent on the borehole section. Table 12.2 indicates the frequency that the borehole should be surveyed during the drilling operation. A higher survey

frequency than indicated in Table 12.2 may be necessary for directional control, e.g., in case of collision risk or during side-tracks.

Table 761.2 Survey frequency during drilling Hole Section Vertical (< 5° Inclination) Build-up/drop-off Tangent

Interval between surveys 120 m 20 m 50 m (MWD: 30m)

783.Definitive surveying/verification surveying It is advised to use the services of an independent contractor to conduct a verification survey when the borehole/section has been completed. The type of survey required is defined in the drilling programme. For offshore surveying jobs the contractor has to be notified at least 48 hours in advance. Survey job preparation:

784.Provide the survey engineer with all the well data upon arrival at the location. 785.Monitor the operating procedures; pre-survey checks and running procedures. 786.Ensure, when checking the final survey, that the quality control criteria given for the tool was followed. NOTES:

1.

As an alternative for a gyroscopic survey, an Enhanced Magnetic Multi-Shot (EMMS) survey is acceptable as a definitive survey in the last hole section.

2.

MWD data might be acceptable as definitive on vertical wells where the inclination is less than 2 degrees.

3.

The accuracy of the EMMS depends on the magnetic storm activity, which is monitored by the survey contractor. If the magnetic storm activity during the EMMS has been too high, a gyro survey can be taken.

4.

The survey contractor should be responsible for presenting the final survey to the Company office.

787.Survey requirements See Table 12.3. The information in this table is only applicable if the survey requirements during drilling have been complied with.

Table 761.3 Verification survey requirements Conductor Surface casing

Survey Requirement At the shoe If surveys show greater than 2 degrees

Intermediate casing

Always

Production casing

Always

Liner section

As advised in the Drilling Programme

Instrument Totco Multi-shot (magn.) Gyro multi-shot Multi-shot (magn.) Gyro multi-shot Multi-shoe (magn.) Gyro multi-shot Gyro multi-shot

788.Definitive survey frequency (verification survey) The maximum acceptable interval between surveys depends on the type of survey to be performed. The intervals are:

789.Gyroscopic surveys 25 metres AH. 790.Inertial surveys 10 metres TVD. 791.Magnetic multi-shot 27 metres AH (1 stand). 792.Tie-on and overlap surveys 793.Openhole magnetic multi-shot surveys should be taken into the last casing shoe to provide a depth check in the survey. 794.There should be a minimum overlap of 300m with the previous survey when gyro surveys are not made from the surface. When the previous survey is also used as an azimuth reference for the next survey, the tie-in point should be chosen such that there is a straight hole section with minimum changes in azimuth and inclination. This is to prevent wireline depth errors/azimuth errors. NOTES:

1.

The first intermediate casing shall be surveyed from surface to TD if the surface casing has been exempted from a definitive survey.

2.

The Enhanced Magnetic Multi-Shot (EMMS) Survey shall include a rotational shot at TD.

3.

If the straight hole section is abandoned, the MWD readings, if available, are accepted as the definitive survey.

795.Survey Instrument Positioning/Running Procedures 796.Magnetic single and multi-shot When making surveys involving magnetic shots, the instrument should be run centralised in a NMDC (non-magnetic drilling collar). The instrument needs to be run centralised in the NMDC to ensure a fixed

orientation of the instrument, with respect to the NMDC, while the survey is being taken. The size of the TOTCO ring and survey barrel should be compatible.

797.Electronic magnetic single-shot The instrument should be run centralised in one joint of NMDC with a spacing of about 50 percent. The instrument needs to be run centralised in the NMDC to ensure a fixed orientation of the instrument, with respect to the NMDC, while the survey is being taken. For inclinations exceeding five degrees, the MSS measurement must consist of a rotational shot. If the azimuth spread in the data exceeds 1.0, the crossaxial correction has to be applied. The size of the TOTCO ring and survey barrel should be compatible.

798.Electronic magnetic multi-shot The instrument should be run centralised in one joint of NMDC with a spacing of about 50 percent. The instrument needs to be run centralised in the NMDC to ensure a fixed orientation of the instrument, with respect to the NMDC, while the survey is being taken. Prior to the survey, a rotational shot similar to that for the electronic magnetic single-shot survey has to be taken. The size of the TOTCO ring and survey barrel shoe should be compatible.

799.Measurement while drilling Prior to testing and operating the MWD tool (Measurement While Drilling), it is necessary to do some checks and tests with the equipment. This involves the following:

800.Conducting a pre-survey Check. 801.Conducting a surface function test. 802.Performing a shallow test. 803.Making a check survey. The Company Representative is to ensure these checks and tests are performed.

804.Ensure the survey engineer has the following information from the drilling programme: 305.Well name/identifier. 306.Wellhead co-ordinates. 307.Interval to be surveyed and distance between surveys. 308.Position of last casing shoe plus size and weight. 309.Tie-in station survey data and all previous survey data. 310.Target azimuth; grid North. 311.Depth reference for surveys. 312.Directional drilling programme. 313.Information on BHA. 314.Mud data. 315.Intended hydraulic programme. 316.The dip angle and field strength of the local earth magnetic field. 805.Ensure that the correct cross-overs are available. 806.Ensure standpipe has a suitable pressure transducer connection (1502 WECO). 807.Ensure the pressure rating of the surveying equipment is adequate. 808.Ensure that appropriate rig utilities are available.

809.Gyroscopic tools North-seeking gyro tools are used for final surveys in cased hole sections. For detailed descriptions, running procedures and quality control criteria refer to the manufacturer(s) documentation.

810.Side track 811.Sidetracks in open hole sections can be oriented and surveyed using magnetic surveying instruments or gyro surveying instruments. 812.Sidetracks out of cased hole sections shall be governed by gyroscopic instruments.

813.Collision Monitoring All surveys have a tolerance. Knowing this, the borehole has a cone of uncertainty. Two or more adjacent boreholes all have cones of uncertainty. Accurate plots shall be made. A fair chance of collision is present as soon as the cones of uncertainty start hitting or overlapping each other. If this criteria is met, drilling must be stopped immediately. Corrective actions shall be discussed with the Drilling Manager. The end result might be a plug-back operation.

Contents

13. COMPLETION FLUIDS ......................................................................................................i 13.1 Introduction .................................................................................................................i 13.2 Base Fluid ...................................................................................................................i 13.2.1 Fluid density .......................................................................................................i 13.2.2 Effect of temperature on density ....................................................................... ii 13.2.3 Formation damage potential ............................................................................. ii 13.2.4 Types and causes of formation damage .......................................................... iii 13.2.5 Effect on base fluid design ............................................................................... iv 13.2.6 Safety and environmental concerns ................................................................. iv 13.2.7 Compatibility with completion equipment ......................................................... iv 13.3 Brine Formulations .................................................................................................... iv 13.3.1 Seawater .......................................................................................................... iv 13.3.2 Sodium chloride ................................................................................................v 13.3.3 Potassium chloride........................................................................................... vi 13.3.4 Potassium carbonate ....................................................................................... vi 13.3.5 Calcium chloride............................................................................................... vi 13.3.6 Calcium bromide ............................................................................................ viii 13.3.7 Zinc bromide .................................................................................................. viii 13.4 Winter Conditions...................................................................................................... xi 13.4.1 Freezing points and crystallisation temperatures............................................. xi 13.5 Mud Formulations .................................................................................................... xii 13.5.1 Salt saturated dolomite mud ........................................................................... xii 13.6 Fluid Analysis ........................................................................................................... xii 13.6.1 Brine analyses................................................................................................. xii 13.6.2 Mud analysis .................................................................................................. xiii 13.6.3 Brine viscosification........................................................................................ xiii 13.6.4 Polymer selection........................................................................................... xiv 13.6.5 Polymer mixing................................................................................................ xv 13.6.6 Mixing procedures........................................................................................... xv 13.7 Lost Circulation ....................................................................................................... xvi 13.7.1 Viscous pills .................................................................................................. xvii 13.7.2 LCM pills ....................................................................................................... xvii 13.8 Packer Fluids ......................................................................................................... xvii 13.8.1 Density requirements ....................................................................................xviii 13.8.2 Corrosion protection......................................................................................xviii 13.8.3 Fluid stability .................................................................................................xviii 13.9 Circulation to Completion Fluid ..............................................................................xviii 13.9.1 Wellbore cleaning..........................................................................................xviii 13.9.2 Displacement of water-based muds to brine.................................................. xix 13.9.3 Displacement of VCM to brine ....................................................................... xix 13.9.4 Preparation for gravel packing ....................................................................... xix 13.10 Filtration ................................................................................................................ xxi 13.10.1 General ........................................................................................................ xxi 13.10.2 Filtration equipment...................................................................................... xxi Illustrations

Figure 13.1 Correction factor for thermal expansion............................................................... iii Figure 13.2 Material requirements for preparation of sodium chloride solutions .....................v Figure 13.3 Material requirements for preparation of potassium chloride solutions .............. vii

Figure 13.4 Material requirements for preparation of potassium carbonate brines ................ ix Figure 13.5 Material requirements for preparation of calcium chloride brines using pure CaCl2 ............................................................................................................................x Figure 13.6 Freezing and crystallisation temperatures of KCI and NaCI brines ..................... xi Figure 13.7 Freezing and crystallisation temperatures of CaCI2 brines................................. xii Tables

Table 13.1 Completion fluid density ranges..............................................................................i Table 13.2 The effect of brine density on HEC ...................................................................... xv

814.COMPLETION FLUIDS

815.Introduction The following guidelines should be considered when preparing completion fluids:

816.The first consideration should always be to ship ready-mixed brines to the offshore rig. Brines can be obtained from mud companies. The mixing of brines on board the rig is often more expensive than ordering them from a mud company. 817.Ensure sufficient quantities of completion fluids, chemical additives and sack material are at the rig site to maintain the required completion fluid quality. 818.Ensure that sufficient pit space is available and that it is thoroughly cleaned out before receiving 'clear' fluids. 819.Due to the fact that harmful chemicals are used, ensure all personnel are aware of the hazards, and that they are provided with the correct safety clothing. Personnel shall be aware of the necessary remedial action to be taken, should spillage’s occur. 820.Proper storage and handling of both chemicals and sack material is the key to minimising accidental damage, spillage and wastage. 821.Check the completion fluid filtration requirements and ascertain the most suitable rig-up. 822.The annulus is to be protected against corrosion using inhibitors, e.g., coat B1900.

823.Base Fluid In Company operations two broad types of fluid are used: 824.Solids-free brines (solutions of salts in water). 825.Solids containing muds. Brines are always preferred with respect to maintenance, limiting formation damage and overall stability at higher densities (> 1.35 sg). The types of brines required present handling, safety and environmental problems, and are substantially more expensive when compared to muds. 826.Fluid density Fluid density is usually selected to provide a minimum overbalance. This is to ensure that formations are killed but minimises fluid invasion, thereby minimising formation damage. Viscous pills are used in conjunction with clear fluids, such as brine, to prevent whole brine fluid loss, minimising formation damage. In fully cased holes where casing integrity is absolutely assured, it may be possible to save money and ease handling by using cheap fluids such as seawater/brine, even though they provide no overbalance to the formation. The density ranges of the commonly employed fluids are listed in Table 13.1. Table 814.1 Completion fluid density ranges Type Brines

Fluid Seawater Potassium Chloride (KCl)

Density range 1.03 1.00 - 1.17

Potassium Carbonate (K2CO3) Sodium Chloride (NaCl) Calcium Chloride (CaCl2) Calcium Chloride/Calcium Bromide (CaBr2) Calcium Bromide/Zinc Bromide (ZnBr2) Salt Saturated Dolomite Mud VCM (packer fluid)

Muds

1.00 - 1.56 1.00 - 1.19 1.00 - 1.36 1.36 - 1.70 1.70 - 2.30 1.22 - 1.80 1.15 - 2.50

827.Effect of temperature on density In cold weather conditions it may not be possible to operate with the above fluids near the top of their density ranges as re-crystallisation will occur. The density of clear brines changes with the temperature due to thermal expansion. The rate of expansion increases with brine density. When calculating required brine densities at the surface, an allowance must be made for downhole temperature conditions as follows: p2 p1 Tav T1 F

= = = = =

Density which should be made up at surface conditions (temperature), kg/m3 Density calculated to provide required overbalance on formation, kg/m3 Average wellbore temperature, °C Surface temperature, °C Correction factor for thermal expansion read from Figure 13.1.

828.Formation damage potential Formation damage is caused by the action of completion fluids and their additives. Usually the extra time and money spent preventing formation damage will pay off during the producing life of a well.

When virgin pressure zones are perforated, a viscous pill may be placed across the lower pressure zones to minimise fluid-loss into depleted zones.

Figure 814.1 Correction factor for thermal expansion 829.Types and causes of formation damage Formation damage can be broadly divided into three types: Completion fluid - formation rock interactions.Completion fluid interaction with the formation rock is usually due to a reservoir containing potassium rich minerals. Exposure to fluids deficient in potassium will lead to leaching of K+ ions and a resultant destabilisation of resident minerals. This can manifest itself as clay swelling, and fines migration, leading to the plugging of pore throats, and formation weakening leading to sand production. Completion fluid - formation fluid interactions. Completion fluid reaction with formation fluid can lead to problems of scaling, precipitate formation, and the formation of viscous emulsions in the pore throats. The use of seawater is especially damaging under these circumstances as it contains a whole range of different salts. Completion fluid particle formation plugging. The presence of solid particles in the fluid can lead to permeability reduction through pore throat plugging. The effect of the particles depends upon their relative size with respect to the pore throat diameter. Only those particles between 1/3 and 1/7 of the pore diameter are considered to be damaging. This fact is made use of in sizing LCM material for use during completions and in fluid cleaning by filtration.

830.Effect on base fluid design To avoid compatibility problems the base fluid is designed to resemble the formation fluid as closely as possible. Interactions with rock are generally combated by using an 'inhibited' brine, usually KCl at lower densities and CaCl2 or CaCl2/CaBr2 at higher densities. Control of particle size and concentration is determined during the well clean-up procedures adopted prior to completion. Where this factor is of concern, filtration will be employed. 831.Safety and environmental concerns The aggressive nature of the acidic clear brines, such as Calcium Bromide, and makes their use potentially hazardous. Consequently, handling is difficult and special precautions need to be taken. At higher densities muds are therefore generally used, except in cases where formation damage potential is considered high. 832.Compatibility with completion equipment In carbon steel completions, corrosion can generally be combated by maintaining a high pH and using appropriate corrosion inhibitors and oxygen scavengers in the packer fluid. In chromium alloy completions, which are subject to accelerated corrosion in the presence of chlorides at high temperature, inert fluids such as condensate or diesel oil may be considered as packer fluids. Brines such as potassium carbonate may be considered if it is essential to have a kill-weight fluid in the annulus. The use of potassium as a completion fluid is, however, problematic due to its incompatibility with formation waters containing calcium or magnesium. Calcium Bromide degrades conventional elastomeric materials such as nitriles, so that the use of these fluids demands expensive premium seals to be used both downhole and in the wellhead.

833.Brine Formulations 834.Seawater Free fluid, available offshore at a density of 1.03sg, is used where formation damage considerations are not foremost, and where overbalance is not required or the reservoir is depleted. To make seawater more formation 'friendly', a 2% KCl is usually added and the pH raised to 9-10, with KOH to provide some corrosion inhibition.

Figure 814.2 Material requirements for preparation of sodium chloride solutions

835.Sodium chloride 836.Cheap fluid for use up to 1.19sg. 837.Material requirements for preparation of sodium chloride brine are presented in Figure 13.2.

838.Use caustic soda (NaOH) to raise pH (0.5kg/m3). 839.Potassium chloride 840.Used for fluid densities up to 1.17sg where an inhibitive fluid is required. 841.Material requirements for preparation of potassium chloride brine are presented in Figure 13.3. 842.Use potash (KOH) to raise pH (0.5kg/m3). 843.Potassium carbonate 844.Used in conjunction with chromium alloy completions at high temperatures, when a kill weight fluid is required in the annulus. The presence of chlorides in solutions in contact with chromium alloy materials induces pitting corrosion and stress corrosion cracking. 845.Densities of up to 1.56sg are achievable. 846.Potassium carbonate will form insoluble precipitates when mixed with water containing divalent cations such as calcium or magnesium. The fluid is therefore not suitable for use as a completion fluid which will come into contact with formation water, as severe formation damage can result. Similarly, mixing with seawater should be carefully avoided. 847.Material requirements for preparation of potassium carbonate are presented in Figure 13.4. 848.Use potash (KOH) for pH control (0.5kg/m3). 849.Calcium chloride 850.Used for fluid densities between 1.20 and 1.36sg. 851.Calcium chloride is available in flake, granular or in powder form and in varying 'purities' of approximately 75, 85 and 95% (wt). The purity refers to the amount of crystal water bound in the structure and does not refer to contaminants. For example, the 75% form contains 25% bonded water. 852.Water used for brine preparation should be free of ions which can cause precipitates when calcium chloride is dissolved, mainly sulphates and carbonates, which will form insoluble calcium carbonate and sulphate. For this reason, calcium chloride brine should never be made up using seawater.

Figure 814.3 Material requirements for preparation of potassium chloride solutions

853.Material requirements for preparation of calcium chloride brine are presented in Figure 13.5 for 100% pure calcium chloride. Material requirements for salts of a different purity can be calculated as follows: Determine the amount of 100% calcium chloride required. Multiply this quantity by a factor 100/x, where x is the purity of the calcium chloride available, to obtain the salt requirement to produce 1m3 of brine. Calculate the water requirement by subtracting the difference in weight (2 - 1) above from the volume of water required to prepare 1m3 of brine in Figure 13.5. 854.Use lime (Ca(OH)2) to obtain the required pH (1kg/m3). 855.Calcium bromide A mixture of calcium chloride and calcium bromide brines used to achieve fluid densities in the range 1.36 to 1.70sg. The fraction of calcium bromide increases with density. It is most economic to compose a brine of required weight using the maximum possible ratio of CaCl2:CaBr2. The maximum CaCl2 content is dictated by the allowable crystallisation temperature, as the crystallisation temperature also increases with the ratio of CaCl2:CaBr2. 856.Use lime (Ca(OH)2) to adjust pH (1 kg/m3). 857.Zinc bromide 858.A mixture of zinc bromide and calcium bromide brines used to achieve fluid densities in the range 1.70 to 2.30sg. The fraction of zinc bromide increases with density. 859.Zinc bromide containing brines are usually mixed from 2 standard solutions or 'liquors' with respective densities of 1.70sg (CaBr2) and 2.30sg (CaBr2/ZnBr2). The volumes of the 2 liquors required to prepare a brine of the required density are calculated as follows: [CaBr2]

= (rZnBr2 - rReq) / (rZnBr2 - rCaBr2)

1 - [CaBr2]

= [ZnBr2]

Where: [CaBr2] [ZnBr2] rReq rCaBr2

= = = =

Volume fraction of CaBr2 required Volume fraction of ZnBr2 required Required density (sg) Density of CaBr2 liquor (1.70sg)

860.Zinc bromides are acidic due to the presence of the zinc ion. The pH of the fluid cannot be raised chemically as an insoluble precipitate of zinc hydroxide would form.

Figure 814.4 Material requirements for preparation of potassium carbonate brines 861.To combat the increased corrosiveness of zinc bromide, manufacturers should supply ZnBr2 liquors with a suitable corrosion inhibitor and oxygen scavenger already incorporated in solution.

Figure 814.5 Material requirements for preparation of calcium chloride brines using pure CaCl2

862.Winter Conditions 863.Freezing points and crystallisation temperatures 864.Winter conditions are defined as when ambient temperature approaches 0°C. 865.Under cold air conditions (below freezing), brine maintenance may need to take account of crystallisation and freezing points. This is not normally a problem but needs to be considered. 866.The solubility of most salts increases with temperature. Crystallisation is the process whereby a brine is made up to a density near the top of its range at a certain temperature. As the temperature falls the brine is no longer able to hold all the salt in solution form and re-crystallisation occurs. 867.The physical effect of salt crystallisation differs for the various brines. In the less dense brines such as sodium chloride, small crystals appear which give the brine a hazy appearance and settle when the brine is left undisturbed. In the more concentrated brines such as calcium chloride and calcium bromide, crystallisation manifests itself as a complete solidification of the fluid. 868.Freezing is simply the formation of ice. The freezing point is depressed by adding more salt. 869.Freezing and crystallisation points of the common brines are presented graphically in Figure 13.6 and Figure 13.7.

Figure 814.6 Freezing and crystallisation temperatures of KCI and NaCI brines

Figure 814.7 Freezing and crystallisation temperatures of CaCI2 brines

870.Mud Formulations 871.Salt saturated dolomite mud 872.A cheaper alternative to high calcium and zinc-based brines when a high-density fluid is required and formation damage is not a great concern. 873.Can be used at densities up to 1.80, but the ease of use and maintenance decreases with increasing density as the solid’s content and viscosity increase. 874.Ensure microdol is used as the weighting material. Dolomite is readily treatable with acid if significant formation damage should occur. 875.Composition per m3 of NaCl saturated water: 317.+/- 40 kg bentonite. 318.+/- ½ kg caustic soda. 319.+/- 20 kg Flocgel LV. 320.+/- ½ kg XC Polymer. 321.Microdol to achieve correct density.

876.Fluid Analysis 877.Brine analyses Routine tests for brines should include: 878.Density using a pressurised balance.

879.Total suspended solids (TSS). 880.pH. 881.Chloride content. 882.Calcium content (usually only for calcium-based brines). 883.Potassium content (usually only for potassium-based brines). Non-routine tests for brines should include: 884.Crystallisation temperature. 885.Brine Clarity (NTU). 886.Viscosity (AV) and gel properties (for viscous pills/brines). 887.Fluid Loss properties (for viscous pills/brines). 888.Polymer content. 889.Oil-water content (when brines are used to displace VCM). 890.Sulphide content (in H2S areas). 891.Mud analysis Routine tests for muds should include: 892.Density using a pressurised balance. 893.Viscosity (PV/YP) and gel properties. 894.Fluid Loss (room temperature). 895.pH. 896.Alkalinity. 897.Chloride content. 898.Calcium content. Non-routine tests for muds could include: 899.Sand content. 900.Potassium content. 901.HPHT fluid loss. 902.Sulphide content (in H2S areas). 903.Brine viscosification Brines occasionally need to be viscosified for a number of reasons. These include: 904.To provide carrying capacity during milling and/or under-reaming operations. 905.To control fluid losses to open formations. 906.As a carrier fluid, for example during gravelpack operations. 907.In general, viscosified brines should be applied in the form of viscous pills rather than viscosifying the whole system.

908.Polymer selection 909.Hydroxy Ethyl Cellulose (HEC) is a polymer which generates a shear thinning fluid in solution form, i.e., the apparent viscosity decreases with increasing shear rate. Practically, this means that brines viscosified with HEC can be easily circulated into place, but have a good carrying capacity for removing debris from the hole, and very low leak-off rates when spotted across a formation. The characteristic feature of HEC is its excellent degradability. Brines viscosified with HEC lose their viscosity by temperature degradation, or they can be broken using acid (usually hydrochloric or sulphuric acid) or a suitable oxidant (usually sodium or ammonium persulphate). HEC leaves a minimum amount of potentially damaging residue after breaking, meaning that formation impairment induced by the viscosity of the fluid is fully reversible. HEC can be mixed as a powder into low-density brines and pre-slurred for use in higher density brines. Because of its temperature sensitivity, the upper workable temperature for HEC viscosified brines is around 100°C, 910.XC Polymer is a xanthan gum which creates even more pronounced shear-thinning fluids than HEC when in solution form. This means that XC polymer performs better than HEC , as far as carrying capacity and fluid loss control is concerned, and a lower concentration is required to provide a similar viscosity. XC polymer displays a resistance to thermal degradation and can only be broken with suitable oxidants. Furthermore, some potentially formation damaging insoluble residue is left over. XC polymer is limited in use to low-density brines, because at high salt concentrations there is not sufficient free water to allow proper hydration. 911.Flocgel is a starch which does not display the shear thinning characteristics of HEC or XC polymer when in solution form, and requires high concentrations to build sufficient viscosity. It does, however, have excellent fluid loss control characteristics due to the fact that the solution contains some undissolved gelatinous matter which deposits a low permeability layer or 'filter cake' on the formation face. Brines viscosified with Flocgel can be broken using an enzyme (e.g., Dexlo-P ex Gist Brocades). However, large amounts of formation damaging residue are left. Flocgel is unstable above 100°C. It can be substituted with Stabilose which is a higher temperature starch, up to 130°C. 912.Final Selection The ready degradability of HEC, coupled with the shear-thinning properties of HEC viscosified brines, makes it the most suitable polymer for any application where the fluid will be exposed to a formation susceptible to formation damage. Where the formation is not open or formation damage is not a concern, XC polymer is preferred due to its superior carrying capacity and fluid loss control. In the absence of XC polymer, or when it proves substantially more economic, starches such as Flocgel can be used where the formation is not open. Starches also have an application where extreme fluid losses require a filter cake to be formed, for instance when under-reaming prior to an external gravel pack. At high temperatures (> 100°C), XC polymer will always be preferred over HEC due to its thermal stability. HEC is always preferred for use in higher density brines.

913.Polymer mixing Due to the shear-thinning nature of viscosified brine rheology, the 'apparent viscosity' (AV) is the best 'field' measurement of viscosity. The AV is defined as the dial reading of a FANN viscometer at 600rpm divided by two. Polymer concentrations required to achieve an AV of 35-45cP in low-density brines (<1.25sg) for milling and under-reaming type operations are: 5 - 7.5kg/m3 3 - 4.5kg/m3 40 - 60kg/m3

HEC: XC Polymer: Starches:

Polymer concentrations required to achieve an AV of 120-150cP in low-density brines for gravel packing carrier fluids and fluid loss pills should, depending on viscosity requirements, be as follows: 7.5 - 11.5kg/m3 4.5 - 6kg/m3

HEC: XC Polymer:

In high-density brines, the initial viscosity of the base fluid is higher than in low-density brines due to the higher concentration of slats. Consequently, less polymer will be required to develop a certain viscosity. The effect of brine density on HEC required (which is the only polymer recommended for use in high-density brines) to develop an AV of 35-45 cP is shown in Table 13.2.

Table 814.2 The effect of brine density on HEC Brine Density (sg) 1.00 - 1.25 1.25 - 1.40 1.50 1.60 1.74 1.85

HEC Requirements (kg/m3) 5 - 7.5 2.9 - 5.7 2.3 - 4.6 1.1 - 2.3 0.3 - 0.6 0.15 - 0.3

914.Mixing procedures All mixing equipment should be thoroughly cleaned before taking in clean base brine. Avoid air entrainment during polymer mixing and pumping. Trapped air can cause foaming (leading to erroneous density measurements), enhanced corrosion and accelerated polymer degradation. Lines and mud guns should, therefore, discharge below the fluid surface, and seals on the suction sides of pumps should be checked to ensure no air is being taken in when circulating. To aid dispersion and full hydration and to obtain properly viscosified brines, HEC or XC polymer should be added no faster than 25kg per 20 minutes. Starch can be added at a faster rate. The formation of 'fisheyes', lumps of dry material trapped by a hard outer hydrated layer, and micro gels indicate that the mixing was too quick. Fish-eyes can be detected visually after scooping with a fine sieve through the mixing tank. Micro gels are difficult to spot and are sometimes only obvious under a microscope. It is good practice to sieve the bag contents via a screen placed above the hopper, to avoid the larger lumps and contaminants entering the system. After polymer addition is complete, the fluid should be sheared, via mud guns if possible, for an absolute minimum of half-an-hour to promote full hydration of the polymer.

When adding polymers to high-density brines, the time required for hydration is longer due to the higher salinity (at high salinity’s there is less free water available). To overcome this problem, polymers should be pre-hydrated in a small batch of fresh water at a high concentration (12kg/m3). Addition of HEC or XC polymer can be accelerated by first reducing the pH of the base fluid. The manufacturers of HEC and XC polymer add a protective coating to the polymer grains which retards hydration and thereby overcomes the problems of incomplete dispersion. This coating is, however, only stable at pH values below 7. By reducing the pH of the brine to 5-6 before adding the polymer, grain dispersion is enhanced and the chances of fish-eyes forming is reduced. The procedure is as follows:

Add 28% HCl to the base brine to reduce pH to 5-6. Add polymer at a controlled rate as above. Stir and shear continuously for 1 hour. Increase pH to 8-9 with the appropriate alkalinity agent for the base brine and shear fluid as above to ensure full hydration. If after following the above procedure the viscosity is not sufficient, do not add more HEC directly to the blend. Rather, repeat the above procedure with the additional viscosifier in a separate tank or drum and bleed it into the main blend. The above procedure is not suitable for calcium-based brines, as their inherent alkalinity means large quantities of acid have to be added to reduce pH. When mixing pills for operations carried out with a potential for formation damage, for example mixing gravel pack carrier fluids, it is essential that all fish-eyes and micro gels are removed from the fluid. The most effective way to condition the fluids is by shearing them thoroughly followed by filtration through an absolute-rated system. If necessary, larger fish-eyes can be taken out by passing the fluid over fine mesh shale-shakers (300 or 400 API mesh). Micro gels can only be removed by filtering through a diatomaceous earth filter, and since micro gels are difficult to detect, all viscous fluids mixed for gravelpack or similar operations must be filtered if possible.

915.Lost Circulation When working with clear base brines against open formations, fluid loss of some form is unavoidable as there is nothing in the fluid to form a barrier to the overbalanced fluid flowing into the formation. This can become unacceptable for the following reasons:

916.Lost returns when circulating preventing debris being carried out of the hole. 917.Excessive fluid invasion of the formation causing formation damage. 918.Uneconomical loss of expensive completion fluids. Curing excessive fluid loss depends on the severity. The following potential solutions are available, in order of preference (to limit formation damage) but in increasing effect:

Reduce hydrostatic head. Viscous pill made up with HEC. Viscous pill made up with XC Polymer. Viscous pill made up with HEC and degradable LCM material. Viscous pill made up with any polymer and non-degradable LCM. Cement.

919.Viscous pills Viscous pills work by drastically slowing down the rate of fluid loss to the formation to acceptable levels, by greatly increasing the viscosity of the fluid. They should not plug the formation. 920.HEC is the preferred polymer for use in fluid loss prevention viscous pills because of its degradability. If it fails to solve the problem it is unlikely that pills made with other polymer will be more successful. 921.Pill volume should take into account the time required to perform, as the pill will continue to seep away at a slow rate into the formation. Whilst some trial and error may be necessary, the volume should be sufficient to fill the casing volume covering the perforations and, have an excess volume of 1m3 for every hour it is required to act, with maximum volumes being limited to 10m3. 922.If the pill is required to act for a very long period of time, a new pill should be spotted every 24 hours to avoid temperature degradation. At temperatures over 100°C this interval should be reduced to every 12 hours, and XC polymer used in place of HEC. 923.Thoroughly shearing and subsequent filtration of the pill will be required to avoid formation damage due to excessive fluid losses. 924.Viscous pills meant for fluid loss control should not contain breakers. If required they should be removed from the wellbore using 15% HCl for HEC pills in non-calcium based brines or a suitable oxidant for other pills. 925.LCM pills LCM material should be carried in a viscous pill. A pill of 5m3 should be used as a first attempt, possibly to be increased if it results in little or no immediate effect. Degradable particles such as calcium carbonate or graded salts should be used. The concentration of LCM material should be 50kg/m3 for consolidated formations with permeability’s up to 1000mD and 150kg/m3 for higher permeability or unconsolidated formations. The LCM material should be graded such that the particle diameter is large enough to bridge on the formation and not invade into it, thus damaging the formation. This is calculated by: dLCM

= (k½) / 3

Where: dLCM k

= diameter of smallest allowable LCM particle (mm) = formation permeability (mD)

Account should be taken of the effect of adding any LCM pills to the overall hydrostatic head acting on the formation. This is particularly true of graded salt pills, which by definition have to be saturated.

926.Packer Fluids Packer fluids are the fluids left in the tubing-casing annulus above the packer during production of, or injection into, the well. A packer fluid must fulfil the following requirements:

927.Serve as an emergency kill fluid.

928.Provide protection against corrosion of the outer tubing wall and inner casing wall. 929.Prevent burst or collapse of the tubing or casing. 930.Be stable and non-degradable in order to continue to provide the above functions. 931.Packer fluids are generally created from the completion fluid by adding certain reagents to allow the fluid to meet the specifications set out above. 932.The actual additives to be used in the packer fluid of a particular well will be programmed following careful consideration of the prevailing downhole conditions and possible laboratory testing. 933.Density requirements Packer fluid densities can be underbalanced provided high quality tubing and casing is run. 934.Corrosion protection In all completions protection against corrosion can be provided by: 935.A compulsory fluid pH of 9-10. 936.Optional addition of an oxygen scavenger (1000ppm sodium sulphite). 937.Optional addition of a film forming amine corrosion inhibitor (e.g., aquatec 0.5%). Ideally, in chromium alloy completions, in addition to the above additives, the base fluid should not contain chlorides. 938.Fluid stability Fluid stability is best ensured by the use of only clean solids-free, polymer free fluids as packer fluids and a high pH. This means there are no solids to settle or products that can degrade.

939.Circulation to Completion Fluid 940.Wellbore cleaning Ensure all surface equipment (tanks, lines, pumps, shale-shakers) to be used in the active brine system, and fluids contained within, are clean before beginning to attempt to clean the wellbore. The BOP's should be cleaned using a jet sub, and the rams functioned to ensure no solids are trapped in this area. Circulation to completion fluid should be carried out from hold-up depth during the last trip into the hole (usually the scraper trip). The hole should be circulated to break any gel structure prior to displacing mud from it. During any displacement, circulation rates should be sufficient to ensure turbulent flow of the displacing completion fluid. Where possible, the string should be rotated and/or reciprocated to aid the development of turbulence.

941.Displacement of water-based muds to brine Displacement spacer sizes should be sufficient to give at least a 3 minute contact time at the circulation rate to be used. Where the formation is open, pills should be suitably weighted to maintain hydrostatic overbalance.

The pumping schedule should be as follows: 942.Viscous brine spacer. 943.Water spacer containing 25kg/m3 lignosulphonate (thinner). 944.Viscous brine spacer. 945.(Seawater/brine until clean - see conditions below). 946.Brine. In an offshore environment, the second viscous brine spacer can be followed by seawater under the following circumstances: 947.The well is fully cased off. 948.The pressure integrity of the casing is proven. 949.There are no restrictions on dumping. When calcium chloride or potassium carbonate are used as the brine, a fresh water spacer of at least 150m length should separate the brine from the seawater. Precipitation of calcium sulphate or calcium carbonate could otherwise occur.

950.Displacement of VCM to brine The pumping schedule should be as follows: 951.Viscous VCM spacer. 952.Viscous brine spacer. 953.Water spacer containing surfactant (concentration vendor dependent). 954.Viscous brine spacer. 955.Brine. Unless filtered, brines used to displace VCM's will inevitably have a small oil content, which prevents them from being dumped. 956.Preparation for gravel packing Gravel packing demands the highest standards of cleanliness because losses have to be induced into the formation to obtain a successful pack. For this reason, it is necessary to clean the work string through which the gravel pack will be performed with acid. The string used to displace brine should include all downhole work string components to be used in gravel packing operations. They should be clean, and where possible, free of rust, loose scale or paint. Pipe dope should be applied sparingly and on the pin end only. Pipe dope squeezed out of a made-up connection should be wiped-off.

The pumping schedule should be as follows: WBM Viscous brine spacer Water spacer + 25 kg/m3 lignosulphonate Water spacer surfactant 15% HCl spacer Viscous Brine spacer Filtered brine

VCM Viscous VCM spacer Viscous brine spacer Water spacer surfactant 15% HCl spacer Viscous Brine spacer Filtered Brine

957.Filtration 958.General Where there is concern about formation damage, the completion fluid will be filtered to provide a fluid whose maximum particle size is known. Filtration requirements are determined by calculating the maximum allowable particle size. This is taken as 1/7 the diameter of the maiden pore diameter: dFIL

=

(k½) / 7

Where; dFIL k

= =

Maximum allowable particle size (mm) Permeability (mD)

959.Filtration equipment Filtration equipment and knowledge is readily available from specialised contractors i.e., Dowell-Schlumberger; Halliburton etc. Job-designed filtration techniques shall be followed.

Contents

14. PERFORATING ..................................................................................................................I 14.1 Introduction .................................................................................................................I 14.2 Preparation..................................................................................................................I 14.3 Explosives .................................................................................................................III 14.4 Perforating Guns ...................................................................................................... IV 14.4.1 Gun selection .................................................................................................. IV 14.4.2 Wireline perforating guns ................................................................................ VI 14.4.3 Tubing conveyed perforating (TCP) gun assemblies ..................................... VII 14.5 Tubing Conveyed Perforating (TCP)......................................................................XIV 14.5.1 Tubing conveyed procedure..........................................................................XIV 14.5.2 Gun preparation .............................................................................................XV 14.5.3 TCP accessory preparation............................................................................XV 14.5.4 TCP assembly make-up, arming and running ...............................................XVI 14.5.5 TCP depth control ........................................................................................XVII 14.5.6 Preparing to fire TCP guns...........................................................................XVII 14.5.7 TCP drop bar actuated firing procedures .....................................................XVII 14.5.8 TCP pressure activated time delay firing procedures ...................................XIX 14.5.9 Dropping the guns.........................................................................................XIX 14.5.10 Retrieving TCP guns to surface ..................................................................XIX 14.6 Retrievable TCP Assembly Procedures..................................................................XX 14.6.1 Equipment preparation...................................................................................XX 14.6.2 Downhole equipment procedures ..................................................................XX 14.6.3 Retrievable packer operations ......................................................................XXI 14.6.4 Surface equipment rig-up.............................................................................XXII 14.6.5 Well killing procedures ................................................................................XXIII 14.7 Wireline Perforating..............................................................................................XXIII 14.7.1 Preparation.................................................................................................. XXV 14.7.2 Arming the gun.......................................................................................... XXVII 14.7.3 Lubricator pressure testing........................................................................ XXVII 14.7.4 Running in hole ........................................................................................ XXVIII 14.7.5 Stuffing box pressure leaks...................................................................... XXVIII 14.7.6 Depth correlation........................................................................................ XXIX 14.7.7 Perforating.................................................................................................. XXIX 14.7.8 Pulling out of hole....................................................................................... XXIX 14.7.9 Gun retrieval................................................................................................ XXX 14.7.10 Stuck perforating guns .............................................................................. XXX 14.8 Correlation Logging............................................................................................. XXXI 14.9 Underbalance..................................................................................................... XXXII

Illustrations

Figure 14.1 Typical perforating gun, equipped with shaped charges ..................................... V Figure 14.2 TCP assembly below a permanent packer .......................................................... X Figure 14.3 Retrievable TCP assembly ................................................................................. XI Figure 14.4 Typical equipment arrangement for lubricator pressure test ......................... XXVI Tables

Table 14.1 Explosives used for perforating.............................................................................III Table 14.2 Schlumberger recommended maximum strip gun lengths................................. VIII Table 14.3 Atlas wireline recommended maximum strip gun lengths .................................... IX Table 14.4 Running speeds for wireline perforating guns............................................... XXVIII

960.PERFORATING

961.Introduction Perforating has the following objectives:

962.To gain access to the reservoir through the wellbore. 963.To provide an opening in the tubing and/or casing to circulate fluids. 964.To provide a pathway to squeeze or circulate cement. This section describes two methods of perforation: tubing conveyed perforating and wireline perforating.

965.Preparation In all perforating operations the following procedures must be followed:

966.A stand-by boat must be present. 967.The Company Representative is the 'Designated Supervisor' with overall control of the operation, including all safety aspects. 968.Only a qualified operator from the service Company is allowed to handle explosives. 969.Perforating operations, including gun loading, can only take place half-an-hour before sunrise to half-an-hour after sunset, although activities that have begun may be finished after sunset if sufficient artificial lighting is available. The only exception to this is if the first shot is in an unknown pressure regime. 970.Perforation of a new geological formation must always be carried out in such a way that first gas or oil comes to surface in daylight. 971.Work may not be conducted when; the work area is not clearly visible (fog); an electrical storm is likely; wind forces are greater than 8; the service Company representative perceives the operation to be unsafe. 972.A safety meeting should be used to discuss all technical and safety aspects of the forthcoming operations. As a minimum, the meeting should include: 322.Company Representative 323.Wellsite Drilling Engineer 324.Well Services Supervisor 325.Logging Engineer 326.Contractor Toolpusher/Rig Manager/Superintendent 327.Driller 328.Electrician 973.Radio silence restrictions must be observed before arming the guns, unless an intrinsically safe blasting cap is used. 974.A qualified electrician must be present to de-energise areas designated by the service company operator. 975.Lubricators must carry a stainless steel band specifying details of the most recent pressure test. 976.The number of personnel authorised to work in the danger area (catwalk, rig floor) should be kept to a minimum. All other personnel should be excluded from these areas and appropriate warning signs positioned at all access routes. During assembly and arming of the guns, no personnel are allowed in the area beneath the rotary table around

the wellhead, BOP's and riser. These restrictions can be relaxed once the entire gun string is below the seabed. 977.Before running in hole ensure that a kill pump with access to one and a half times the hole volume of kill fluid is connected to the X-mas tree, and is pressure tested and make sure that the check valve is functional. 978.Ensure the rotary table is locked. 979.The lock-out cap of the hydraulically actuated master valve on the Xmas tree should be installed when the gun passes through the tree valves (up or down) and should be removed when the toolstring is 50m or more below the seabed. 980.Part used explosives, for example primacord, must not be left lying around on the rig floor or catwalk area. 981.Tubing conveyed perforating (TCP) guns may not be retrieved to surface without first retrieving the detonating device (drop bar). Gun Loading:

982.The Company Representative, Rig Manager or Contract Toolpusher, crane divers and deck pusher (head roustabout) should be informed about the area where explosives are stored and handled. 983.No welding, smoking or heavy overhead lifts are permitted in the area where explosives are stored and handled. 984.All spare and scrap explosives should be stored in the approved explosives stores. Gun Handling, only for TCP guns;

985.TCP guns are heavy. They should only be moved by crane, forklift or air hoist. The proper handling caps or pick-up subs must always be installed when the guns are moved. 986.The rig crew should assemble the guns under TCP service Company supervision. Due to the externally flush nature of the guns, careful use of slips and safety clamps (dog collars) is required to avoid accidentally dropping the guns into the well.

Operational Checklist:

987.Ensure the explosives are the correct type for the downhole temperature conditions, and are stored in an approved container in a suitably protected area, (approved explosives stores). 988.Ensure radio silence is not only in force when arming the gun, but maintained during its retrieval and is only relaxed once the guns have been confirmed fired or disarmed. 989.Identify any welding sockets and other sources of electrical power, and ensure that they have been isolated to prevent stray currents from prematurely firing the guns. 990.Be aware of any approaching fog, adverse weather or lighting risk that could interfere with perforating operations. 991.Keep the number of personnel on deck to a minimum in the area where the gun is being armed.

992.Make up one and a half times the hole volume of kill weight fluid in the pits and line up to the kill/cement pump. 993.Ensure any electric-line or wireline BOPs are tested prior to being rigged up. 994.For wireline perforating, ensure that the pressure control equipment is rigged up so that if an unfired gun becomes stuck across the lubricator, due to a frayed cable jamming in the grease injection tubes, the tree valves may be fully closed and not obstructed by the toolstring. Otherwise the well may have to be killed. 995.Good communication is essential between the logging cab, the drillfloor, the central control room (if on a production platform) and wellbay to avoid tree valves being inadvertently opened or closed. Always count the turns when opening or closing these valves. 996.Ensure sufficient toolstring weight is run to overcome wellhead pressure and to allow the well to be flowed, if required, whilst perforating. 997.New formations must be perforated to bring hydrocarbons to surface in daylight.

998.Explosives There are three techniques of well completions categorised under perforating. These are:

999.Shaped Charges. 1000.Bullet Charges. 1001.Sand Jetting. Only the first method (Shaped Charges) will be discussed as the other two methods are seldom used in Company operations. Deep penetrating (DP) charges are used in all applications except gravel packing, where Big Hole (BH) charges are considered to encourage a more efficient pack. Shaped charges were developed during the Second World War to provide a method of penetrating metal plating. In 1945 this method was adopted by the petroleum industry to penetrate casing, and was found to be far superior to conventional bullet charges. A typical perforating gun equipped with shaped charges is shown in Figure 14.1. The explosives used for perforating are shown in Table 14.1. The primary explosive is lead azide and is used in the detonating cap, while the secondary explosive is most commonly RDX and is found in the primacord and perforating charge.

Table 960.1 Explosives used for perforating Common Name Chemical Formula Molecular Weight Melting Point (0C) Detonatio n Pressure (kbar) 1

1

2

C14H6(NO2)6

C17H7N3(NO2)8

291.3

316.2

221.1

296.2

450

621.3

204

273

319

360

347

393

190

242

) Primary Explosive

300

2

) Secondary Explosive

HNS

2

C4H8N4(NO2)4

95

HMX

2

C3H6N3(NO2)3

141

RDX

2

C5H8(NO3)4

Explodes

PETN

2

Lead Azide PbN6

PYX

Secondary high explosives are categorised into five types: PETN, RDX, HMX, HNS, and PYX. The type of explosive used is dependent upon the maximum anticipated time downhole before firing and the downhole temperature. Explosives degrade progressively both with time and increasing temperature. The maximum exposure time at bottom hole temperature is generally taken as 100 hours. This means the ratings for the various explosives are: PETN: RDX: HMX: HNS: PYX:

???°C 115°C 155°C 230°C 260°C

When used beyond the given ratings, the secondary explosives may either have a reduced performance, or may fail to initiate or burn without exploding, producing high gas pressures but no jet.

1002.Perforating Guns Perforating guns are run on wireline tubing or drillstring. Wireline guns are fired electronically, whereas the tubing conveyed guns are fired by pressure from a drop bar. Figure 14.1 shows a typical perforating gun equipped with shaped charges.

1003.Gun selection TCP guns offer a superior perforating technique and are therefore first choice, in offshore locations. The additional benefits of TCP perforating over wireline are:

1004.The use of TCP guns is less costly when perforating long intervals because of the substantial savings in rig time as compared to multiple wireline runs. The completion and perforating assembly can be run in the well on one trip (if the guns are to be left in the well).

Figure 960.1 Typical perforating gun, equipped with shaped charges

1005.TCP perforating is inherently safer because: 329.There is a lower susceptibility of the primary explosive in the firing head being accidentally detonated: There is no electric blasting cap, mechanical firing heads can be utilised. 330.Pressure tested surface wellhead equipment is installed prior to perforating, ensuring continuous well control for the perforating phase, as well as the flow/clean-up phase.

331.H2S: The system is completely secured prior to perforation. In this manner sour gas can be more easily controlled. NOTE:

This method is generally not used for critical sour gas wells.

1006.Efficiency: Guns are available in sizes up to 184mm and charges up to 32g. Wireline perforating is used under the following circumstances:

1007.On offshore platforms where there is to be a significant amount of time between completion and perforation, causing concern about the degradation of the explosives. 1008.There is insufficient 'pocket' below the bottom shot to allow dropping of the TCP guns and wireline access is required below the tailpipe after firing. An alternative is to run a separate perforating trip with a retrievable TCP assembly. 1009.As a back-up to TCP perforating in case of a misfire, or where additional or reperforation is considered necessary below a permanent packer. 1010.Wireline perforating guns There are two categories of perforating carriers or guns:

1011.Hollow Carrier, either steel or aluminum. 1012.Strip or Wire Carriers. Hollow Carriers are further subdivided into two classifications: 1013.Casing Guns. 1014.Through Tubing Guns. Casing guns are available in sizes from 3” (79mm) to 51/2” (140mm). They are a thick walled tubular carrier with threaded ports in which the charges are secured. The ends of the carrier are sealed to protect the charges and detonator from wellbore fluids and pressure. The gun is designed to absorb the shock generated by the charges and is reusable until the recommended diameter is exceeded. The guns should be checked after usage and discarded if the recommended tolerance is exceeded. Usually 8 - 10 runs on a single gun are all that can be expected. Through tubing guns are either semi-expendable strip carriers or hollow carriers, and are made in sizes ranging from 111/16" to 21/8". These guns are so called as they are run through production tubing or drillpipe on the wireline. Due to the smaller size of the hollow carrier small charges must be used, and therefore the hole diameter and depth of penetration of the perforations is not as great as with a casing gun. The guns are not reusable as the ports are machined, not threaded. Phasings are generally limited to 0° and 180° and shot densities of up to 19 shots per meter can be installed.

Strip and Wire Carriers A strip carrier consists of a metal strip into which holes have been punched to accept charges. Phasings are generally limited to 0° and 180° and shot densities range from 1 to 19 shots per meter. A wire carrier is composed of several pieces of stiff, shaped, large diameter wire, which when assembled as a unit are able to hold charges. Phasing and shot density are the same as for a strip carrier.

The advantage of this type of carrier over hollow through tubing carriers is that these carriers can be loaded with a bigger charge without exceeding the same diameter of the through tubing gun. The bigger charges exhibit superior perforating performance over the charges loaded in a through tubing gun. The disadvantage of wire and strip carriers is that there is more debris left in the wellbore and, that the charges loaded into the strip or wire carrier are more subject to environmental conditions such as temperature, pressure and corrosive fluids. Wireline Perforating String The perforating wireline toolstring usually consists of:

1015.Cable Head. 1016.Sinker Bars. 1017.Casing Collar Locator (CCL). 1018.Magnetic Positioning Device. 1019.Blasting Cap. 1020.Perforating Gun. 1021.Nose or Bull Plug. If required, a downhole pressure gauge can be included in the string when shooting underbalanced to monitor the downhole pressure response after firing. The gauge is cushioned to withstand the shock forces encountered during firing. Through-tubing perforating guns are run on a 3/16" or 7/32" monoconductor cable, thus allowing the use of a lubricator.

Lubricators The main components of an electric-line lubricator are identical to those used for braided wireline:

1022.Grease Injection Control Head. 1023.Ball Check Valve. 1024.Tool Catcher. 1025.3" or 3½" ID Riser Sections. 1026.Twin hydraulically controlled BOP fitted with moulded rams. Recommended Maximum Gun Lengths:

1027.Hollow carrier guns are less prone to buckling than strip guns. Consequently, the limits on hollow carrier gun lengths are generally dictated by the length of the available lubricator, but should not exceed 12m. 1028.Service Company recommendations for the maximum length of through tubing strip gun to run in one trip to avoid problems are determined by the gun type, casing size, shot density and the well fluid as shown in Tables 14.2 and 14.3. 1029.Tubing conveyed perforating (TCP) gun assemblies Introduction

1030.TCP guns are deployed in one of two methods: 332.Below a permanent packer (either wireline or hydraulically set) and then dropped off into a sump to allow access to the perforations. 333.On a retrievable packer assembly and then retrieved prior to running the completion string, for example before gravel-packing or where there is insufficient room to drop the TCP guns and wireline access is required below the tailpipe. 1031.TCP assemblies for both methods are illustrated in Figures 14.2 and 14.3. Guns

1032.The threaded connections between gun sections are 6 pitch ACME incorporating at least one O-ring seal. Ballistic connection to the detonator in the firing head is achieved by self-aligning detonation transfer modules, whereby the primacord boosters are automatically placed side-by-side when making up the guns. 1033.The last gun section is sealed off with a rounded end 'bull plug'. 1034.4½" Liners are generally perforated using 33/8" TCP guns with 6 shots per foot phased at 60°. 1035.7" Liners are generally perforated using 5" TCP guns with 12 shots per foot phased at 60°. 1036.The maximum length of TCP gun that can be run below a wireline set packer is determined by the allowable weight on the cable used to set the packer and, therefore, the weight of the total TCP assembly. The allowable weight must be confirmed with the electric wireline contractor. In practice, around 25m of 33/8" guns or 15m of 5" guns can normally be run.

Blank sections

1037.Blank sections are simply unloaded gun sections containing a primacord with selfaligning detonation transfer boosters at each end.

Table 960.2 Schlumberger recommended maximum strip gun lengths Gun Type 111/16" Strip 111/16" Strip 111/16" Strip 111/16" Strip 21/8" Strip 21/8" Strip 21/8" Strip 21/8" Strip 111/16" Strip 111/16" Strip 111/16" Strip 111/16" Strip 21/8" Strip 21/8" Strip

Casing 41/2" 41/2" 7" 7" 41/2" 41/2" 7" 7" 41/2" 41/2" 7" 7" 41/2" 41/2"

Shot Density 4spf 4spf 4spf 4spf 4spf 4spf 4spf 4spf 6spf 6spf 6spf 6spf 6spf 6spf

Well Fluid Gas Liquid Gas Liquid Gas Liquid Gas Liquid Gas Liquid Gas Liquid Gas Liquid

Maximum Length (m) 8 6 12 12 6 6 12 12 6 4.5 12 12 6 4.5

21/8" Strip 21/8" Strip

7" 7"

6spf 6spf

Gas Liquid

12 12

Table 960.3 Atlas wireline recommended maximum strip gun lengths Gun Type 111/16" Strip 111/16" Strip 111/16" Strip 111/16" Strip 21/8" Strip 21/8" Strip 21/8" Strip 21/8" Strip 111/16" Strip 111/16" Strip 111/16" Strip 111/16" Strip 21/8" Strip 21/8" Strip 21/8" Strip 21/8" Strip

Casing 41/2" 41/2" 7" 7" 41/2" 41/2" 7" 7" 41/2" 41/2" 7" 7" 41/2" 41/2" 7" 7"

Shot Density 4spf 4spf 4spf 4spf 4spf 4spf 4spf 4spf 6spf 6spf 6spf 6spf 6spf 6spf 6spf 6spf

Well Fluid Gas Liquid Gas Liquid Gas Liquid Gas Liquid Gas Liquid Gas Liquid Gas Liquid Gas Liquid

Maximum Length (m) 6 6 12 12 6 6 12 12 6 6 6 9 6 6 6 9

Figure 960.2 TCP assembly below a permanent packer

Figure 960.3 Retrievable TCP assembly

Bar actuated, absolute pressure fired firing heads

1038.The preferred type of firing head is an absolute pressure fired firing head actuated by a detonator bar. 1039.The firing is a sequential mechanical action. When the drop bar hits the impact head, it breaks the shear pins securing a ball-release and shifts it down. This movement releases the balls holding the firing pin. After the firing pin is freed, hydrostatic pressure acting via the ports propels it into the percussion detonator. 1040.The amount of hydrostatic pressure required to activate the detonator depends upon the model: 334.Vann Model IID: 86.25bar (1 250psi 335.Vann Model IID: 17.25bar (250psi 336.Schlumberger: 24.15bar (350psi) 1041.The firing head is mounted on top of a primacord extension housing and inside a 'fill joint', usually a 23/8" EUE pup joint, to allow debris to settle past the top of the firing head around the extension housing. 1042.The firing head features the following inherent safety features: 337.The guns cannot be fired at surface even if the ball-release is depressed since absolute pressure is required to actually fire the guns. 338.A no-go inserted in the EUE connection on top of the fill joint minimises the chance of accidentally dropped objects firing the guns. 339.If the guns should flood, they cannot be fired as the pressure would then become balanced across the firing pin. 1043.The detonator bar is a solid bar fitted with an upper fishing neck and a brass impression block or 'telltale' on the lower end. It can be allowed to free fall or can be run on wireline and jarred down. When run on wireline it can either be run screwed directly to the jars or on a Camco JUC running tool. Absolute pressure hydraulic time delay firing head

1044.In applications where a mechanical action is impossible, such as horizontal wells, an absolute tubing pressure activated time delay firing head is used. The tubing is pressured up to a pre-determined point which activates a timing mechanism. A predetermined time delay then allows pressure to be bled off to create underbalance before the guns actually fire. 1045.On breaking pre-set shear pins, the applied pressure causes a piston to travel upwards, forcing oil slowly through a small orifice into a chamber at atmospheric pressure. When the release sleeve, which is lined to the travelling piston, is raised past the locking fingers, the fingers open outwards and the firing pin is propelled downwards by the remaining pressure into the percussion blasting cap. 1046.The time delay is determined by the orifice size, taking into account the downhole pressure and temperature conditions. It can be varied between 5 and 60 minutes. 1047.The safety spring supporting the firing pin disables the firing head once the hydrostatic pressure goes below 600psi (41.4bar), making it impossible to accidentally detonate the guns at the surface. Gun release subs

1048.Mechanical or automatic release mechanisms can be run to drop off fired gun assemblies, provided sufficient rathole is available. After dropping, the remaining tubing end is smooth with an internal taper to act as a wireline re-entry guide. Ported pressure equalising sub

1049.The ported sub, fitted with a glass disc, is run in a TCP assembly to prevent any debris falling on top of the firing head. Shock absorbers

1050.Both a vertical and radial shock absorber are included in a retrievable TCP assembly to prevent the retrievable packer from becoming unseated. They are not considered necessary below permanent packers in Company operations. 1051.Both shock absorbers are run below the packer. Ensure that the vertical shock absorber is run above the radial shock absorber. Retrievable packer

1052.The retrievable packer is used in TCP applications. 1053.Prior to running the packer, the Tooloperator will fill out a worksheet that calculates the effect of internal and external pressure on the workstring. This will ensure that it is not inadvertently unseated by the applied pressures. 1054.The calculation routine will provide the correct set-down weight required to prevent the tension sleeve from prematurely shearing for the given conditions. 1055.The worksheet will also serve as a check to ensure that both the workstring and casing are not mechanically damaged by the forces generated by the applied pressure. Safety joint

1056.A safety joint is run above an RTTS packer to allow drillpipe removal should the retrievable packer become stuck. 1057.In an emergency, the safety tension sleeve must first be parted by pulling on the drillpipe. The safety joint is completely released by holding right hand torque on the drillpipe whilst working it up and down (stroking) to back out the nut, which requires 10 turns to fully back out. Three strokes per turn are generally required.

Jar

1058.A jar is included in a retrievable TCP assembly to aid in removal of tools if they become stuck. 1059.The jar provides this function by temporarily resisting a pull on the toolstring caused by a hydraulic time delay in the jar. Resistance is released when the metering sleeve inside the jar moves into the bypass section of the outer case, allowing the special hydraulic oil to bypass rapidly. As many impacts as needed may be delivered by setting down weight to re-cock the jar and repeating the above procedure. Circulating valve

1060.A circulating valve is included in the gun assembly to allow circulation above the packer between drillpipe and annulus, and additionally to act as a shut-in for the assembly. 1061.The tool should be designed so that it is impossible to unintentionally expose the annulus to flowing formation fluids. Safety circulating valve

1062.A safety circulating valve is used as a back-up circulating valve, operated by annulus pressure, used if the circulating valve should fail to operate when it is required to kill the well. 1063.This is a one-shot tool only. It is usually pinned to shear at around 1 000psi (69bar) above the cycling pressure of the circulating valve. Surface test tree

1064.The surface test tree is used to provide a controlled flow path for any fluids produced after firing under-balanced and for controlled well killing. 1065.The solid block tree consists of: 340.A manual wing valve for kill line connection. The kill line is connected to the rig pumps with a check valve installed to protect against back-flow. 341.A flow wing valve with an hydraulic actuator. The valve may be actuated manually or automatically by emergency shut-down pilots in the flow system. 342.A swab valve to allow wireline entry through the BOP's via a lubricator. 343.A master valve. 344.A swivel to allow correct orientation of the tree when made up to the top of the drillpipe and prevent the elevators from turning when applying torque to the drillpipe. 345.A lifting sub on top of the tree allows the weight of the tree and retrievable TCP assembly to be taken on the rig elevators. 1066.A kelly cock is usually placed between the swivel and the top joint of pipe to enable the well to be closed in case of a leak in the swivel.

Choke manifold

1067.The flow line from the hydraulically actuated wing valve is connected to a choke manifold to allow full control of flow from the well after perforating. 1068.A five-fold configuration is used to allow a full bore flow path through the manifold and total bypass of choke control. On one side of the bypass, an adjustable choke is used, allowing more flexible control for wellbore flow-back. The other side of the bypass contains a fixed choke.

1069.Tubing Conveyed Perforating (TCP) TCP is a perforating operation that is run on a tubing string. TCP is used in deviated and horizontal holes. Tubing Conveyed Perforating - TCP is used primarily to provide a high underbalance pressure at the time of perforating. The large pressure differential created provides a method of clearing perforation tunnels of debris that is a product of perforating. Well control is the secondary consideration in utilising TCP.

1070.Tubing conveyed procedure The following procedure should be followed when conducting tubing conveyed perforating (for more detailed instructions see the corresponding paragraphs in this section):

Run bit and scraper to PBD and drift casing if a packer is to be used. Ensure that there is sufficient sump if the guns are to be left in the hole; (required sump = gun length + 5m.) Displace hole to clean fluids. Make up the perforating assembly as per specifications provided in the completion program.

Check all downhole profiles to ensure that the GR tool will travel down the R/A collar, and that the detonating bar will reach the firing head. Check the R/A collar with the GR tool prior to running in the hole to ensure that a signal is present. RIH with the perforating assembly. Place the guns on depth by tubing tally. Check the depth setting by gamma ray tool on wireline. Adjust setting depth. If a packer is used then set the packer at this time and land the dognut. Rerun the gamma ray correlation to ensure that the assembly is set at the specified depth. Adjust the assembly if necessary and rerun the correlation. Nipple up the wellhead and install an adjustable choke on the flowline. Stake or weight the flowline every 10 minutes to the flare pit or rig tanks whichever is to be used. Remove all unnecessary personnel from the wellhead and flowline area. Drop the detonating bar to perforate the well. Flow the well to clean up. 1071.Gun preparation Due to the fact that TCP guns contain only secondary explosives, they can be loaded either on the rig or at the service company base prior to usage. On arrival at the rig site, the guns should be visually inspected for signs of damage incurred during transit. Calliper all OD's to ensure compatibility with the casing/liner ID. Cross-check the perforating intervals by requesting to see a copy of the original document requesting the perforation. Mark the perforation intervals in the reference log to be used for perforating. Measure the length of each individual gun and blank section and ensure the perforating intervals, shot density and shot phasing are consistent with the perforation programme. 1072.TCP accessory preparation All TCP accessories should undergo the same inspection and preparation routine applied to tubulars which consists of: 346.Thread inspection and cleaning. 347.Drifting. 348.Length measurement. Some relaxation of the acceptance criteria may be sensibly applied to any components expected to be dropped after firing. When using a drop-bar actuated hydraulic firing head, confirm with the TCP service engineer the minimum hydrostatic head required to fire. Check that this will be available downhole, taking into account the required underbalance. Ensure the drop bar has an upper fishing neck and a lower impression block. Ensure the correct fishing tool is on site of retrieval. When using an hydraulic time delay firing head, confirm with the TCP service engineer that the firing head has been pinned to begin its countdown at the required absolute pressure, and that the orifice has been sized to give the required time delay before firing.

Ensure the activation pressure is less than the completion test pressure. Ensure downhole temperature has been taken into account. Ensure that the length of the firing head itself is not included in the total TCP assembly running length, as it is entirely enclosed by the fill joint. Ensure a mechanical release sub is installed, this should be drifted with a dummy shifting tool to ensure compatibility. When an automatic release sub is used, check with the TCP service engineer that the release sleeve has been pinned such that the downhole pressure remaining after firing will be sufficient to shear out the release sleeve. Check that the glass disc in the ported pressure equalising sub is whole. 1073.TCP assembly make-up, arming and running The firing head assembly is picked up with the detonator installed. Due to the inherently safe nature of the firing head, it is made up exactly as the other gun sections with strict adherence to safety procedures. The following procedures should be followed for making up TCP guns, blank sections and the firing head:

Lay out guns, blank sections and the firing head on the catwalk in the correct order. Pick up items one at a time in the proper sequence with a crane. As the guns are picked up they should have a lifting sub on the top connection and a handling cap (or a bull-nose in the case of the first gun section) on the bottom connection. The firing head assembly is equipped with an EUE connection, and consequently can be picked up without the use of a lifting sub. Transfer to the elevators. Use a safety sling in case the elevators accidentally open. When picking up the first gun section with the bull-nose, lower the gun into the hole and set the slips carefully around the gun. Install a safety clamp (dog-collar). Release the elevators and replace the lifting sub in the top connection with a handling cap to protect the boosters. When picking up subsequent sections, lower the upper gun to a practical height above the lower gun. Remove the handling caps. Check the booster position in both sections. Carefully stab the upper gun into the lower gun and make-up the connection (approximately 1 000 - 1 500ft-lbf) with chain wrenches. Take the entire weight of the string back on the blocks. Lower the gun into the hole and set the slips carefully around the gun. Install a safety clamp (dog-collar). Release the elevators and replace the lifting sub in the top connection with a handling cap to protect the boosters. Pick up the next gun section and repeat the procedure until the firing head has been installed. Pressure testing of TCP assemblies is not required. Since TCP guns utilise a one-piece steel loading strip to secure the charges and boosters, the gun assembly is fairly resistant to damage during RIH. Normally, the running speed will be dictated by some other equipment item in the gun string, such as the packer. However, sudden jarring motions from stopping or restarting should be avoided. Special care should be taken when running through a liner top or when tagging packers or plugs.

1074.TCP depth control Three methods are used to ensure that the guns are at the correct perforating depth:

1075.Running a through-tubing GR/CCL to tie a reference point in the string into open hole reference logs before setting the packer. This is the method most used. 1076.Running the guns below a wireline set packer. This is restricted to short TCP guns only. 1077.Calculate the exact position of the completion/drillstring with respect to the formation and the distance to be moved up or down to get exactly on depth. When placing TCP's on depth, always pick up to the final depth. If tagging a plug to determine the position of the packer, ensure full string weight up is regained before beginning to measure the distance to be moved.

1078.Preparing to fire TCP guns Before firing the guns ensure the following:

1079.The cementer is on standby at the unit for new formation perforations. 1080.The guns are on depth and the packer is set. 1081.The completion string is pressure tested. 1082.Surface equipment, flow and kill lines are correctly rigged up and pressure tested. 1083.All surface valves are in the correct positions with the kill line open and the flowline closed in at the choke manifold. 1084.Pressure detection equipment is functioning correctly. 1085.No restrictions on perforating apply, e.g., at night. 1086.The correct underbalance has been achieved or a designated hydrostatic head to fire the gun. 1087.All personnel are aware of the imminent firing. 1088.A safety meeting has been held. 1089.A standby boat is on location. 1090.The SSSV is fully open. 1091.TCP drop bar actuated firing procedures The procedures for the drop bar actuated firing system are as follows:

Rig up wireline lubricator on Xmas tree or surface test tree with the drop bar installed on the closed swab valve. Pressure test the lubricator to the maximum expected THP. Adjust THP to create the required drawdown. Equalise pressures over the swab valve and open the swab valve to allow the drop bar to fall. Close the swab valve when convinced the drop bar has gone. The fall time depends on many parameters including depth, deviation, fluid in the completion string and tubing ID, but 350m/min is a useful rule of thumb. Under normal circumstances the velocity of the bar will be sufficient to break the glass disc.

Firing can be detected audibly, by a pressure response (either up or down) when perforating underbalanced or by using a hydrophone or 'shot detection system' on the flowline. If twice the estimated time required for the bar to reach the firing head has been exceeded and there is no indication of firing, proceed as follows:

Bleed down THP and open up the flowline to the separator and see if the well will flow. If the well does not flow, depressurise and break out the lubricator and check that the drop bar has dropped. If the drop bar has dropped, slowly increase the tubing pressure until the pressure below the packer is just above the formation pressure and observe for leak-off to confirm perforations. If leak-off is observed it can be concluded that the reservoir is too poor to produce. If no leak-off is observed, rig up and pressure test the lubricator containing the appropriate fishing tool for the fishing neck of the drop bar. Run in hole slowly until the drop bar is located. The problem can usually be ascertained from the position that the drop bar is located. Examples include: 349.Drop bar at firing head level implies excessive debris on top of the firing head, flooded guns or a poor reservoir that will not produce (mechanical release sub). 350.Drop bar at ported equalising sub level implies excessive debris on the glass disc. 351.Drop bar at landing nipple level implies that the drop bar is standing up on an internal shoulder. Gently set down the fishing tool and pick up to ascertain whether the bar has been fished by observing the line weight. If embedded in debris it may be necessary to jar upwards to release the drop bar. Pick up approximately 10m and go down fast in an attempt to pass the obstruction and/or activate the firing pin. If necessary, jar down to get through debris. If all attempts to reach the firing head fail or the guns will not fire, pull out of hole and inspect the brass impression block at the base of the bar to decide further action: 352.A clear indication of contact with the firing pin implies that either the guns did fire and the reservoir would not produce, or the guns failed to go off. In the latter case the guns will have to be either retrieved and rerun, or alternatively dropped off and the well perforated with through-tubing wireline guns. 353.An indication that the firing pin has not been contacted implies debris is preventing access to the firing pin. In this case, in addition to the options to drop or retrieve the guns, the debris can be cleaned out utilising coiled tubing or wireline bailers. In wells with high deviation (between 30° and 60°) or where debris is expected to be a problem, it is recommended to run the drop bar on wireline in the first place. In this case proceed as follows:

Adjust THP to create the required drawdown. Rig up wireline lubricator on Xmas tree or surface test tree with the drop bar installed on the wireline toolstring. Pressure test the lubricator. Equalise pressures over the swab valve and run in hole to gently tag the glass disc. If excessive debris is suspected on top of the disc, jar down through the debris. Pick up about 5m then go down fast to break the glass disc and carry on to impact the firing head.

Observe for indications of firing mentioned above. When satisfied that the guns have fired, retrieve the drop sub on the wireline. 1092.TCP pressure activated time delay firing procedures Procedures for the absolute pressure activated system are as follows:

Pressure up the tubing to the predetermined upper level to shear the pins and hold for 1 minute. Bleed off the pressure quickly to adjust THP to create the required drawdown. Wait for the predetermined time delay and observe for indications of gun firing. These can be an audible 'ping' or a pressure response and may include the use of a shot detection system (hydrophone). If no shot is detected after twice the estimated delay, proceed as follows:

Open the flowline to the separator to see if the well will flow. If the well will not flow, slowly increase the tubing pressure until the pressure below the packer is just above the formation pressure and watch for leak-off to confirm perforations. If no leak off is observed and the activation pressure has not been reached, attempt to activate the guns by pressuring up to completion test pressure. Bleed off the pressure quickly to adjust THP to create the required drawdown. Wait for the predetermined time delay and observe for indications of gun firing. If there is still no indication of firing, the guns will either have to be retrieved or dropped and the well perforated with through tubing wireline guns. 1093.Dropping the guns When using a mechanical release sub, this is activated by jarring up with and utilising a wireline lubricator to enter the well. After dropping the guns, tag the top of the resulting fish with the shifting tool to confirm that the guns have dropped to the correct depth. Do not pass the top of the fish and risk jamming the wireline tool. When using a mechanical release sub, it is normal to produce the well clean through the perforated pup joint before dropping the guns, in order to maximise the benefits of perforating under drawdown. When using an automatic release sub, it is still good practice to determine the top of the resulting fish with a wireline dummy shifting tool before proceeding with any operations below the resulting tubing tailpipe such as production logging.

1094.Retrieving TCP guns to surface NOTE:

Under no circumstances should the guns be retrieved without first retrieving the drop bar. Due to the safety features of the firing heads (neither type can fire without the presence of a certain minimum hydrostatic pressure), gun retrieval does not represent a special safety hazard. However, the safety procedures (See 14.2) should continue to be observed.

Retrieval procedures are as follows:

Pull out of hole as normal with drillpipe or as with tubing until the gun assembly is reached. At this stage, all unnecessary personnel should leave the area above, below and at the rig floor. Pull the string high enough such that the top perforating holes of the top gun can be seen. If the guns have not fired, assume that there is pressure trapped inside the gun string. Open the bleed-off vent in the firing head adaptor to relieve trapped pressure. Break firing head connections and remove the detonator to disarm the guns. Break down the gun string at each inter-gun connection, observing the reverse procedures to making up the guns with proper use of lifting subs, handling caps and safety clamps. It may be necessary to use rig tongs to break out tight connections.

1095.Retrievable TCP Assembly Procedures 1096.Equipment preparation The following equipment preparation guidelines should be considered:

1097.Retrievable TCP assembly accessories do not require the extensive inspection procedures applied to permanent completion components. A general visual inspection for obvious transit damage and length measurement is normally the only requirement. Retrievable TCP assembly accessories are generally threaded 31/2" IF connections for repeated make up and break out. 1098.Ensure running OD's of all equipment are consistent with the casing/liner ID, but note that the blocks on the radial shock absorber are meant to be slightly larger than the casing ID. Ensure that the blocks on the radial shock collapse easily. 1099.Ensure the correct size and type of retrievable has been delivered. Ensure the packing elements are undamaged and the slips are sharp. 1100.In consultation with the test tool service engineer, ensure the force required to part the tension sleeve in the safety joint is less than the yield value of any other components in the string. 1101.In consultation with the test tool service engineer, ensure the nitrogen charge in the circulating valve is correct for the required annular cycling pressure of the circulating valve (usually 1 500psi [103.5bar]). Ensure the downhole pressure and temperature have been taken into account. Verify that the valve has been functionally tested through all positions in the contractors's shop. Ensure the circulating valve is in the blank position when installed in the assembly. 1102.In consultation with the test tool service engineer, ensure the safety circulating valve has been pinned to shear at least 1 000psi (69bar) over the cycling pressure of the circulating valve. 1103.Check surface test tree and choke manifold valve function. 1104.Downhole equipment procedures Retrievable TCP assembly downhole equipment is brought to the rig floor using lifting subs and handling caps and the 31/2" IF connections made up to the correct torque with chain tongs as per drilling BHA components. Care should be taken to avoid setting slips or rig tongs directly on the body of any test tools if it can be avoided. Use a safety clamp above slips when no external upset is present on the pipe body.

Ensure external circulating ports are free before running in hole. The circulating valve is run in the blank position. This allows the string to be internally pressure tested at intervals and when ready to set the packer. Additionally it allows the string to be filled with brine only until the correct underbalance is obtained. Thereafter, the string is not filled but run with an air 'cushion'. General running procedures are as follows:

Make up the retrievable TCP assembly: 354.TCP Guns 355.Safety Spacer 356.Firing Head 357.One Joint EUE Tubing 358.Ported Sub with Glass Disc 359.EUE Spacer Tubing 360.Crossover 361.Radial Shock Absorber 362.Vertical Shock Absorber 363.Retrievable Packer 364.Safety Joint 365.Jar 366.Circulating Valve in blank position 367.Safety Circulating Valve 368.Six Drill Collars. 369.31/2" Drillpipe to surface. RIH, filling pipe to create the required drawdown. Space out such that: 370.The TCP guns are on the correct depth for perforating (See 14.5.3). 371.About 0.5m of drillpipe is sticking above the rotary table. 372.There are no tool joints across the pipe rams. Circulate through the ported sub to clear any debris. Set the retrievable packer and set the string in the slips. Close the pipe rams around the drillpipe and cycle the circulating valve to the 'welltest' or straight through position. Each cycling pressure should be applied for one minute before releasing. Keep the drillpipe open. If the packer is not sealing this will be noticed immediately as the annular fluid will U-tube into the drillpipe. Rig up surface equipment (see 14.6.4) and perforate (see 14.5). 1105.Retrievable packer operations The following retrievable packer operation guidelines should be considered:

1106.To verify that the mechanical slips are free before going into the hole, allow the tool to hang free in the blocks and work the drag body up and down several times. The slips should move in and out freely. 1107.To set the packer: 373.Run tool slightly below setting position. 374.Pick up to setting position.

375.Rotate pipe several turns to the right. Only half a turn is required on bottom, but several turns are normally made using the rotary table to ensure torque is worked down to the packer. 376.Hold the right hand torque in the pipe whilst slacking off until the mechanical slips on the packer body begin to take weight. 377.Relieve torque by turning pipe to the left. As left hand torque is applied, move tubing down until the desired amount of weight is on the packer. 1108.To unseat the packer equalise pressure across the packer and lift the tubing without turning. 1109.Surface equipment rig-up The flowhead assembly is made up prior to running the TCP guns and comprises:

1110.Flowhead with hydraulically actuated flow wing valve and manually operated master, swab and kill wing valves. 1111.Swivel below the flowhead. 1112.Kelly cock below the swivel. 1113.Kill and flow lines with low torque valves. The flowhead assembly is tested to the programmed test pressure prior to running the TCP guns, as follows:

1114.Through the kelly cock against the underside of the closed master valve. 1115.Through the kelly cock and open master valve against the closed swab, kill wing and flow wing valves with the low torque valves open. 1116.Through the kelly cock, open master valve and open kill and flow wing valves against the closed low torque valves in the lines. 1117.Through the kill wing valve and master valve against the closed kelly cock. Following a successful pressure test, no connections should be broken until all perforating operations are complete. After the packer is set, the flowhead assembly is made up to the top drillpipe joint. The kill line is connected to the pump unit and the flow line to the choke manifold. Pressure testing continues as follows:

1118.The kill line is tested against the closed kill wing valve. 1119.The flow line is tested against the close choke manifold through the open kill and flow wing valves. 1120.The choke manifold valves are selectively tested through the open kill and flow wing valves. The test pressure has to be maintained for a period of at least 10 minutes. Leakage depends on time because the tortuous path fluids may follow through voids between threads and/or because of the slow displacement of viscous but non-sealing thread compound. A pressure drop of up to 10% of the initially applied pressure is acceptable as long as the pressure remains constant for a period of at least 10 minutes. All pressure tests should be recorded on a chart and signed by the Drilling Supervisor or Company Representative supervising the test. Original charts must be readily available for scrutiny upon request.

1121.Well killing procedures After perforation and inflow is complete, the following well killing procedures should be performed:

Retrieve the drop bar on slickline using a lubricator to enter the well against well pressure. Cycle the circulating valve to the circulating position by applying the required annulus pressure (circulating ports closed and ball valve open). Bleed of any drillpipe pressure and reverse circulate out any hydrocarbons from the string with fluid, taking returns via the choke manifold. Any oil contaminated returns should be diverted to a separate storage tank. Shut-in the drillpipe and cycle the circulating valve to the well test position (circulating ports and ball valve open). Open the drillpipe. Open the pipe rams, take the weight of the assembly on the blocks via the flowhead lifting sub and pull the slips. Unseat the packer (See 14.6.3) by straight pull. Reverse circulate twice the hole volume, taking returns via the choke manifold. Any oil contaminated returns should be diverted to a separate storage tank for disposal. NOTE:

At this stage the newly perforated formation is exposed to a full column of overbalanced fluid and losses may ensue. The packer should be unseated and lost circulation pills should be circulated into position if possible. If the packer cannot be unseated due to high differential pressures across the packer, lost circulation pills should be bullheaded down the drillpipe.

When an acceptable level of losses has been achieved, break out the flowhead assembly and retrieve the TCP assembly, pulling out slowly to avoid swabbing. Take the precautions (See 14.5.10) when retrieving the guns to surface. If the circulating valve fails to cycle into the circulating position to kill the well, pressure up further and activate the safety circulating valve. In this case, the tubing will remain plugged below the safety circulating valve circulating ports and there is no circulating route below the packer. On unseating the packer, any losses have to be dealt with by bullheading down the annulus.

1122.Wireline Perforating The following procedures should be followed when conducting wireline perforating. For more detailed instructions see the corresponding paragraphs in this section:

Contact the specified perforating company to notify them as to the time that they are required to be on location, interval to be shot, gun type and size, charge size, phasing shot density and expected temperature and pressure. NOTE:

The requested guns are to be loaded prior to arrival on location.

NOTE:

All safety precautions are to be followed as outlined, see 14.2.

NOTE:

Under no circumstances is the detonator to be loaded into the perforating gun prior to arrival on location.

When the perforating company arrives on location check to ensure that the requested gun has been supplied. NOTE:

If there is the possibility of electrical storms occurring during the perforating phase, then operations should be suspended until the weather clears.

If the perforator is not in use, store it in a convenient place away from the current operation. Place the gun on the catwalk. Check the OD of the gun to ensure that it will pass through all downhole profiles. Check the OD of the collar locator to ensure that it will pass through all profiles as well. NOTE:

Do not approach the perforating gun from the side, but from either end.

Pressure test the lubricator with the wireline installed. The required pressure will be specified in the program. A typical equipment arrangement is shown in Figure 14.4. A GR or neutron correlation log can be run at this time. Unless a gun gamma arrangement is used, the guns will be placed on depth with the CCL. If pip tags are installed for depth correlation, check the response by placing the GR tool adjacent to the tags and check for a response. Check to ensure that the casing to rig is properly grounded. The maximum voltage measured in the grounding circuit should not exceed 25V. Do not proceed until the circuit is properly grounded. The resistance of the gun circuit should also be checked prior to installing the cable head. This will ensure that the gun will conduct the voltage required to fire the detonator. Shut off all radio transmitters and generators prior to installing the detonator and making up the CCL/casing gun assembly. Any perforating track panels not in use should be disconnected. Make sure that only authorised personnel are present at the catwalk and wellhead areas. When the detonator is installed and the perforating assembly is complete a final check of the CCL to top shot measurement should be made. The Company Representative may stand at the end of the perforating gun while the measurement is made. The CCL should have a measuring point marked on it. WARNING: Do not approach an armed gun from the side.

Zero the odometer relative to the KB elevation prior to RIH. Running speed should be 40 50m/min. The wireline should be coated with a corrosion inhibitor while RIH in a sour environment (7 500ppm H2S).

WARNING: If the tool circuitry is malfunctioning and the gun is returned to the surface, the detonator must be disconnected prior to locating the electrical problem.

Run a CCL strip to pick up at least five collars which will cover the zone of interest. Make note of the correction required to place the CCL on depth. The gun is always to be placed on depth by logging into the zone. Make one last check of the correlation log to ensure that the collars match. Check that the odometer(s) reflect the measured distance (as per Step 13) from the CCL to top shot. The top odometer is usually the CCL while the bottom odometer will be the top shot.

Detonate the perforating gun. Look for indications that the gun has fired. When the perforating assembly has been returned to the lubricator, the odometer should zero at the same point as it did prior to RIH. If it does not, the following checks should be made: 378.Was the running speed in excess of 50m/min, as this will cause odometer slippage. 379.Is the odometer wheel worn down to a reduced diameter. This will result in a higher measured depth than the actual depth recorded at the zone of interest. Once it is ready to rig out, watch for trapped pressure. The lubricator pressure should be fully bled off. Once the perforating operation has been completed, all explosive remnants and debris should be removed from the wellsite by the perforating company. 1123.Preparation The following guidelines for wireline perforation should be considered:

1124.The logging service company should be provided with the following data: 380.A complete sketch of the well, including location of tubing tails, liner tops, packers and nipples, etc. 381.The required perforating intervals. 382.The reference log to be used for perforating. 383.The cased hole logging report. 1125.Ensure that the correlation log to be used for perforating, usually the CCL/GR on the cement bond log is on depth with the log used to select the perforation intervals. Mark the perforation intervals on the reference log to be used for perforating. 1126.Cross-check the perforating intervals by requesting to see a copy of the original document requesting the perforation. 1127.Check the perforating string OD and ensure it will pass through the completion string. A wireline dummy run to below the bottom perforation should be carried out prior to running perforating guns.

Figure 960.4 Typical equipment arrangement for lubricator pressure test 1128.Calculate, in consultation with the logging engineer, the number of sinker bars required in the perforating string. 1129.Visually inspect the gun before the detonator is connected ensuring: 384.The number of shots and overall length of the guns and spacers is consistent with the required intervals to be perforated. 385.All screws are properly tightened. 386.All shoulders on the gun assembly should be chamfered to prevent hanging up on nipple profiles, etc. 1130.Measure the distance CCL measure point to top shot and confirm this with an independent measurement taken by the logging engineer.

1131.Calibrate the CCL, and GR if used. 1132.Arming the gun The following guidelines should be considered when arming the gun:

1133.Once radio silence is in force and no stray voltages have been detected in the cable head, arm the gun. WARNING: All personnel must be out of the line of fire at this stage.

1134.Ensure the detonator is placed in a detonator safety tube before untwisting the lead wires and connecting to the gun. 1135.Lubricator pressure testing Lubricators and BOP's are workshop tested to maximum rated pressure every 12 months. A metal band indicating the date and test pressure is located on the lubricator and should be inspected to ensure the lubricator can meet its required usage. Lubricators suitable for use with H2S are marked accordingly with a separate metal band. NOTE:

Ensure that the riser has the correct dimensions to contain the largest and longest tool expected to be used.

NOTE:

No connections on the lubricator should be broken following a successful test. When rigged up on a well with SITHP, the BOP's and lubricator should be fully tested at the commencement of each series of wireline runs, and not necessarily before every run.

The test procedure for wells with no tubing head pressure is as follows:

With the upper master valve open and the swab valve closed, install the dual wireline BOP's on top of the Xmas tree. Close the lower BOP's around the polished test rod appropriate to the cable size to be used. Ensure that the test rod is chained down to prevent movement during application of pressure. Fill the body of the BOP's with water and close the upper rams. Slowly apply pressure between the rams, bleeding off air until the system is full, then test between the rams to the maximum anticipated tubing head pressure for 15 minutes. If the test is unsatisfactory, visually inspect the BOP's to determine the leak path. Bleed off the pressure, partially open the rams, remove the polished test rod, close the upper master valve and open the swab valve and kill wing valve. Assemble the riser and hydraulic grease tube with the cable head and perforating string. Make up to the BOP's and pull up to within 0.5m of the tool catcher. Fill the lubricator and hydraulic grease tube with completion fluid very slowly, until all air has been evacuated. Keep the stuffing box closed to prevent the tool being lifted into the tool catcher. The lubricator is full when test fluid is observed coming from the exhaust hose on the hydraulic grease tube. Once a seal has been established, slowly crack open the swab valve to equalise the pressure in the lubricator to the available tubing head pressure. Observe for leakage for 15 minutes. Fully open the BOP rams and run in hole.

When filling up the lubricator with liquid, this should be done very slowly to avoid 'burning' the cable due to air being expelled at high rates between the cable and the flow tube walls of the stuffing box. The fill rate is generally kept low enough to keep the pressure less than 69bar. In gas filled wells, gas from the wellhead is used to pressure test the lubricator to prevent the formation of hydrates in the lubricator. In the presence of wet gas, glycol is always injected during the operation to prevent hydrate formation. The BOP rams are kept closed to act as a tool trap until ready to run in hole.

1136.Running in hole Check the cable magnetic marks near surface and add extra marks for close control when pulling out. Mark the position of the last cable layer on the drum when the gun is positioned below the wireline BOP by a metal pointer attached above the drum so that the exact position of the gun is known when pulling back into the lubricator. Stop the tool in the tubing every 500m and check the hanging weight, allowing any slack caused by cable friction to be taken up. Check periodically that the grease seal is holding the well pressure. Take extreme care when passing through tubing downhole accessories, such as landing nipples and tailpipes, and also when going through the liquid levels. Recommended running speeds are given in Table 14.4.

Table 960.4 Running speeds for wireline perforating guns Tubing size 5"

Gun type Strip

Hole contents First run (m/hr) Subsequent runs (m/hr) Liquid 3000 3000 Gas 5000 6000 Carrier Liquid 3000 3000 Gas 5000 6000 1 3 /2" Strip Liquid 2500 2500 Gas 4000 4000 Carrier Liquid 3000 3000 Gas 5000 5000 NOTE: The above speeds are possible under ideal conditions. Abnormal conditions such as excessive hole deviations, poor tubing condition etc. should be taken into account and the speed reduced accordingly. Running in speeds should not exceed 1 000m/hr when reaching and operating below the lower completion accessories.

1137.Stuffing box pressure leaks In the event of a seal being lost on the cable at any time, follow these procedures:

Stop the cable and check grease injection pressure which should be around 34.5bar above wellhead pressure during all operations. If sufficient grease injection pressure is being maintained, close the exhaust hose tap and the stuffing box. Increase the injection pressure to regain a seal. On regaining a seal, open exhaust and stuffing box and if seal still holds, proceed, maintaining the new injection pressure.

If the leak still persists, close the BOP rams around the cable, injecting grease between the rams if necessary. Bleed off pressure above the BOP's and re-establish grease flow. Equalise the pressure in the riser, open the BOP's and proceed. 1138.Depth correlation All correlation runs using the CCL and/or GR should be made logging up and the gun put in position for firing with the gun moving in the same direction. When shooting multiple intervals with strip guns it is preferred to shoot the lowest interval first and progressively work up the hole. This minimises the possibility of debris from blocking intervals not yet perforated. This procedure usually applies to carrier guns too, but is less critical since less debris is generated. Log up over the interval to be perforated. Where present, use any pup joints or joints of distinctive length to correlate the CCL on the perforating string to the CCL on the field reference log as long as the distance between the perforating interval and the distinctive joint is not more than 30m. Ensure the field reference log, usually the CCL from the cement bond log, is on depth with the reference log used to select the perforation interval, usually the neutron-density log. If not make the appropriate corrections. It is possible to feed the depths of the casing collars from the reference log into the on board computer in the logging unit and allow depth correlation to be carried out automatically. After depth correction, always relog the interval to prove that the perforating string is now on depth with the field reference log.

1139.Perforating When perforating for the first time in a new reservoir, have the cementer unit standing by. When perforating underbalanced, check that the THP is consistent with the required underbalance prior to perforating. When firing look for indications that the gun has fired. These can include:

1140.A reduction in cable tension. 1141.Ammeter (current) readings. 1142.A pressure fluctuation (can be up or down) when perforating underbalanced. 1143.A slight change in depth recorded by the CCL. 1144.Pulling out of hole After perforating with strip guns, the guns should be held static for 5 minutes to allow any debris to settle. This precaution is not necessary with carrier guns. Never run down after perforating. When picking up, record the 'after firing' CCL as a final record of perforating depth. A slight discrepancy between the before and after firing log is an indication that the gun has fired. Due to the possibility of the guns becoming distorted during firing and the possibility of cable armour balling, extreme care should be taken when:

1145.First picking up the gun after firing. 1146.Entering the tailpipe. 1147.Passing through any restrictions such as nipples and SSSV's. 1148.Gun retrieval Regardless of any indications to the contrary, always assume that the guns have not fired when retrieving to the surface. For this reason, radio silence restrictions must be in force before pulling the gun string above 50m below the seabed level, unless an intrinsically safe detonator is in use. Radio silence should be maintained and all personnel kept out of the direct line of fire until the gun has been confirmed by the logging engineer to be completely fired. At 50m below the seabed, re-install the lock-out cap on the hydraulic master valve. When near surface, observe for the multiple magnetic marks and the cable layer on the drum to indicate the position of the gun. When the tool head is beginning to enter the lubricator, which on some lubricators is indicated by the activation of a mechanical flag, the logging crew should pull the cable by hand until the perforating head makes a positive engagement in the tool catcher at the top of the riser. If this is impractical due to the weight of the tool, the winch should be used with extreme caution. A positive engagement in the tool catcher is indicated by applying a little more hand pull on the line which should have a 'play' of about an inch. When the gun is confirmed to be completely in the lubricator the gun should be retrieved via the following procedure:

Close the swab valve on the tree counting the number of turns to ensure nothing is trapped over the valve. Close the hydraulic master valve and re-open the swab valve. Vent the lubricator via the choke manifold. Close the flowline valve and bleed off any remaining pressure in the lubricator with the pressure release needle valve. Confirm there are no trapped pressures with the back-up needle valve. Close the swab valve and disconnect the lubricator from the wireline BOP's. If the connection is difficult to break it could be indicative of residual pressure in the lubricator. After retrieving the gun from the lubricator, lay the gun on the catwalk and disconnect the perforating head and blasting cap from the shaped charges by cutting through the prima cord. Remove the blasting cap and render safe by twisting the leg wires together. Before carrying out the next run inspect the gun for any unfired charges and, if present, ascertain the reason why they did not fire. Check the insulation and continuity of the cable. If any of the charges did not fire it may be necessary to reperforate over the same interval.

1149.Stuck perforating guns If the gun string becomes stuck, attempts should be made to free the gun without endangering the weak point. This usually limits available pull to 75% of the weak point rating, but this should be confirmed with the logging engineer depending on the well conditions. Possible actions include:

1150.If possible, go down and try pulling up past the obstruction again. 1151.Try picking up at various speeds.

1152.Bleed off or pump up wellhead pressure. 1153.Flow the well (only after confirmation from the Drilling Manager). If the tool remains stuck, work on the cable gradually, increasing tension slowly until it breaks at the weak point. If the cable does not part with a tension of weak point rating plus 25%, it may be necessary to use a cable cutter to cut the cable at the cable head. After breaking the cable, consideration should be given to killing the well to facilitate retrieval of the cable. If the well is pressured and the decision is taken not to kill the well, retrieving a cable to surface under pressure requires a higher than normal risk and requires specific procedures and extra safety precautions:

Hold a safety meeting with all personnel involved to discuss the procedure to be followed. All personnel not essential to the operation shall be cleared from the wellhead rig floor area. Ensure that the proper means of communication between the operator at the lubricator and the winch operator are available and in use. Lower the top logging sheave as much as possible to reduce the free length of cable above the lubricator. Retrieve the cable slowly and with extreme caution near the surface to prevent the cable being ejected out of control from the lubricator. Increase and manipulate the grease injection pressure to control the cable speed. Do not use the wireline BOP's to apply friction. Observe for the multiple magnetic marks which indicate that the end of the cable is nearing the surface. Close the swab valve as soon as the end of the cable is in the lubricator, counting the number of turns to ensure nothing is trapped across the valve. Bleed off lubricator pressure, see 14.7.9. After recovering the cable, make a wireline run with a lead impression block to ascertain the gun's position. If the gun has fallen to the bottom of the hole, it will frequently be left there if it does not hinder any other operations. If the gun was not fired, explosives will degrade and will not self detonate. If the gun is stuck, three options are available:

1154.Jar the gun free and push to bottom with a blind box run on wireline. 1155.Mill up gun utilizing a mud motor-mill assembly run on coiled tubing. 1156.The remaining fishing neck allows the gun to be retrieved with a pulling tool, jars and accelerator, run on wireline or coiled tubing. 1157.Kill the well and fish with tubing or drill pipe.

1158.Correlation Logging Correlation logs can be run prior to the perforating run, with the perforating gun (gun gamma tool) or when the CBL (Cement Bond Log) is run. In any case, the following procedures should be followed:

The correlation log will consist of a GR-CCL combination or a neutron-CCL combination. It is of utmost importance that this log be placed on depth correctly. Otherwise the guns may be detonated off depth. Check the running speed of the open hole log. The correlation log should be run at the exact same speed. This will eliminate shifting of the gamma ray log due to differences in the tool response lag.

If the reference point (measuring point to top shot) of the CCL is not clearly marked on the outside of the tool, then check the reference point by passing a metal object past the tool and record the position at which a response is measured. The CCL response can be used to check casing weight. An increase in casing weight will be presented on the log as an increase in the magnitude of the signal. This can be used to correlate log depth to the casing tally and may also be used to indicate a reduction in the internal diameter of the wellbore.

1159.Underbalance The procedure for circulating to underbalance through a Side Pocket Mandrel (SPM) is as follows:

Rig up and pressure test a wireline lubricator with a kickover and pulling tool for the SPM dummy valve. Retrieve the SPM dummy valve leaving the SPM ports open. Straight circulate the well to the required volume of underbalance fluid (diesel or nitrogen) via the kill wing valve, taking returns from the annulus to an Expro measuring tank to monitor the liquid level inside the tubing. The liquid level must not be allowed to fall below 100m above the SPM in order to avoid contaminating the annular fluid. Restrict flowrates to 300l/m to avoid washing out the SPM pocket. NOTE:

Calculate the hydrostatic head of nitrogen required due to its compressibility.

Run a SPM dummy valve, tag liquid level and latch the dummy into the SPM. Prior to perforating, adjust THP according to the measured liquid level to create correct underbalance at the formation.

Contents

15. STIMULATION .......................................................................................................... XXXV 15.1 Introduction ........................................................................................................ XXXV 15.2 Stimulation fluids ................................................................................................ XXXV 15.2.1 Acid types.................................................................................................. XXXV 15.2.2 Acid additives ........................................................................................... XXXVI 15.2.3 Fracture fluids .......................................................................................... XXXVI 15.2.4 Fracture fluid additives ............................................................................. XXXVI 15.2.5 Fracture proppants................................................................................... XXXVI 15.3 Stimulation equipment...................................................................................... XXXVII 15.3.1 Acid stimulation surface equipment ........................................................ XXXVII 15.3.2 Hydraulic fracturing surface equipment ..................................................... XXXIX 15.4 Preparation procedures..................................................................................... XXXIX 15.4.1 Operational checklist...................................................................................... XL 15.5 Safety ...................................................................................................................... XL 15.6 Acidising................................................................................................................. XLI

15.6.1 General ......................................................................................................... XLI 15.6.2 Pump pressure and rates.............................................................................. XLI 15.6.3 Displacement ............................................................................................... XLII 15.6.4 Post-acidisation clean-up ............................................................................. XLII 15.7 Fracturing ............................................................................................................. XLIII 15.7.1 Fracturing procedures .................................................................................XLIV Illustrations

Figure 15.1 Schematic rig-up for stimulation ................................................................ XXXVIII Figure 15.2 Decision tree (low injectivity) .......................................................................... XLIII

1160.STIMULATION

1161.Introduction Stimulation and acidising are non-routine operations. Prior to starting these operations a pre-job safety meeting shall be held. The functional responsibilities of the well site staff/supervisory personnel shall be reviewed at the safety meeting. All safety precautions shall be discussed in detail. An acid treatment is to achieve the following objectives:

1162.Dissolve reservoir rock to improve the flow. 1163.Dissolve scale formed by injection or production. 1164.Dissolve drilling particles, deposited in the reservoir matrix. 1165.Dissolve fine cement particles, plugging off perfs. 1166.Dissolve formation parts plugging the pores. A hydraulic fracture treatment is conducted to improve well productivity in wells having:

1167.Near wellbore formation damage. 1168.Naturally low reservoir permeability. Both stimulation techniques require accurate, tailor-made programmes. These programmes shall be designed by experienced and specialised engineers/contractors.

WARNING: Spent acid and acid contaminated water cannot be dumped into the sea. Also proper arrangements shall be made in advance to handle this waste stream (offshore and onshore).

1169.Stimulation fluids 1170.Acid types The acids most commonly used in well stimulation treatments are:

1171.Hydrochloric (HCl)

- dissolves carbonates.

1172.Hydrofluoric (HF) - dissolves both carbonates and silicates.

The acids are used, in combination (mud acid) but HCl can be used alone. They are normally stored by service companies at 36% (wt), then diluted with fresh water for field use to various strengths as follows:

1173.Sandstone: 387.15% HCl 388.12% / 3% HCl/HF (Full-strength acid mud) 389.12% / 1.5% HCl/HF (Half-strength acid mud) 390.7.5% HCl 391.6% / 1.5% HCl/HF

1174.Carbonate: 392.28% HCl 393.15% HCl The amounts of acids used varies from 0.1 to 1.0m3/m perfs, dependent on the required treating radius, porosity, field experience and type of damage to be treated.

1175.Acid additives All acids are combined with chemical additives. These are used to prevent additional formation damage occurring through the interaction of stimulation fluids with formation fluids. All acid formulations include:

1176.Corrosion inhibitor. 1177.Silt suspending/anti-sludge agent. 1178.Iron sequestering agent. 1179.Surfactant/alcohol. 1180.Diverting agent. 1181.Pre-flush, post-flush and displacement fluids. 1182.Fracture fluids The most common carrier fluid types are:

1183.Water-based gel. 1184.Water/oil emulsion. 1185.Gelled diesel oil. 1186.Foam. 1187.Fracture fluid additives The frac fluid must be kept in such a state that it is viscous enough to carry the proppant, but not so viscous that it cannot be pumped. To achieve this the following additives are used:

1188.Fluid loss reducer. 1189.Friction loss reducer. 1190.Viscosifiers. 1191.Breakers. 1192.pH buffers. 1193.Emulsifiers. 1194.Fracture proppants Proppant is used to maintain the opening in the fracture, thus providing a permeable flow path. Usually sand or sintered bauxite is used as a proppant because these materials are spherical and of uniform size to maximise permeability. It is pumped into the well with the carrier fluid. Sintered bauxite is more expensive than sand, but it is stronger and is used to withstand closure pressure that would crush other proppants.

1195.Stimulation equipment 1196.Acid stimulation surface equipment The equipment used and its rig-up will depend on the size and nature of the job, i.e., volumes and types of fluids to be pumped, and pump horsepower required. Only approved 'frac' iron is to be used for rigging up temporary high-pressure lines. Screw-type Weco connections are outlawed because of the potential for the threads to strip under high pressure. Acid will be transported to the rig in 1 500gal. fibreglass lined transport tanks. It is generally transported in neat form (36% conc) and diluted to the job strength requirements at the wellsite. Additives are transported as sacks/drums for mixing on site. Figure 15.1 shows a schematic rig-up. Storage/Mix Tank:

1197.Acid will be placed in a storage/mix tank.

Blender:

1198.The blender is used to treat the acid to the job specifications. It has either a 50 or 100bbl. tank for batch mixing and a centrifugal pump. Acid is circulated from the storage tank, treated and returned until the required volume has been prepared. 1199.During the job the blender pump is used to precharge the main pump.

Figure 1160.1 Schematic rig-up for stimulation Pump:

1200.The main pump consists of a Horizontal Triplex type pump with either a V8 or V16 power unit.

1201.Rated at 800HP with a 4" Fluid End, to a maximum pressure of 1 035bars. Lines:

1202.Acid will be directed from the pump to the wellhead via 2" high-pressure chicksan lines. 1203.The storage/mix tank, blender and main pump are connected using low-pressure hoses, either 2" or 4". 1204.The high-pressure line from the pump to the well will contain a flowmeter (to monitor volumes) and one or more check valves (flapper type valve). 1205.Hydraulic fracturing surface equipment Offshore, all storage, mixing, pumping and monitoring equipment is preferably located on a Dynamic Positioned Frac Boat (owned by Halliburton or Dowel Schlumberger). The boat is connected via a Coflexip hose and quick release to a "Saddle" on the rig side. The "quick release" is needed for cases where the boat suddenly has to break away from the rig.

1206.Preparation procedures Before commencing stimulation operations the following should be complied with:

1207.Ensure monitoring equipment (pressure / pump rate / cum. volume) work properly and back up is available. 1208.All equipment that requires pressure testing is to be given a 15-min. test to a pressure higher than the expected fracturing or injection pressure. This pressure shall not exceed the safe working pressure. 1209.Mixing tanks and lines must be clean. 1210.Check volume of freshwater for acid mixing, and additive concentrations. Take samples of acid for quality control. 1211.Ensure well equipment (surface and downhole) is adequate for the maximum injection pressure: 394.Ensure the X-mas tree rating is adequate. 395.Ensure the tubing, casing and liner lap are pressure-tested. At high pump rates it may be necessary to apply annulus pressure to reduce pressure differential across the tubing. 396.Ensure the tension, burst, and collapse rating of the tubing will not be exceeded. 397.Ensure the downhole equipment (packers, sleeves, safety devices, side pocket mandrels) is in proper operational condition and all materials are compatible with the fluids to be pumped. 1212.Check that the treatment interval (perforations, open hole) is in a proper condition for the planned treatment. 1213.Estimate the length of the job based on the expected pump rate and volumes to be pumped. The pumping schedule should allow flowback of spent acid the same day. 1214.Calculate relevant volumes (tubing, pockets) to estimate when fluids are at the perforations. 1215.Calculate the required hydraulic horsepower of pumps by: HHP (Effective) = Pump pressure (bar) x Pump rate (m3/min) x 2.24

1216.Operational checklist 1217.Quality control all stimulation fluids and materials to be pumped (i.e., acid strength, proppant size/sphericity/strength, freshwater purity, corrosion inhibitor, etc.). 1218.Confirm acid tanks are top-discharge, pump or compressed air displaced, properly lined type vessels. 1219.Verify that all frac/stimulation iron is suitability rated for the job in hand. Ensure no threaded-type connections are used. 1220.When pumping acids, ensure all the required safety equipment is available, and that spillage containment teams and procedures have been set up. Specify the correct neutralising agents for each acid type. 1221.Stimulation work may only be carried out during daylight hours. Ensure that the job pumping time is finished with sufficient time to produce spent acids the same day. 1222.Verify maximum pumping pressure. 1223.Ensure mixing tanks and lines are clean prior to pumping. 1224.Check that the mechanical status of the well is adequate for the maximum anticipated test pressures. 1225.Ensure all measuring equipment is calibrated, functional and that back-ups have been provided.

1226.Safety 1227.Stimulation work may only be carried out during daylight hours. 1228.Identify all possible hazards, e.g., inflammability and toxicity of fluids or reaction products, high pressure, etc. 1229.Equipment and materials to be spotted to facilitate easy escape of personnel in emergency situations. Layout drawings must be available. 1230.Have a proper communication system during the job (headphones, walkie-talkie). 1231.Follow a check list to ensure all pressure lines are tested, anchored and suitably identified. 1232.Lines from the pumping unit to the wellhead should have a non-return valve installed as close to the wellhead as practical. 1233.Personnel exposed to equipment under pressure must be kept to an absolute minimum. 1234.Appropriate protective clothing (flame retardent coveralls, respirator, goggles, gloves and boots) should be worn by all personnel handling acid or other corrosive chemicals. 1235.Acid causes severe burns. Ensure a shower unit is rigged up in the work in case of an emergency. 1236.Have sufficient quantities of a neutralising agent, water, and a 'hose down' team on standby in case of acid spillage. 1237.Proper medical facilities onsite and medical personnel should be informed as to the type of operation being conducted.

1238.Prior to stimulation operations conduct a safety drill for all persons involved: 398.Explain alarm procedures, escape routes, survival and emergency equipment location. 399.Outline the procedure to be followed in case of leaks, H2S release, etc. 400.Outline job procedure, designate the sequence that fluids will be injected or circulated and at what rates treatment is to be pumped. 401.Identify duties of each key person during the job. 402.Review communication system. 403.Discuss chemical hazard. 404.Identify the location of eyewash bottles, safety showers, medical personnel. 1239.After completion of the job all equipment that has been in contact with the acid must be washed inside and outside.

1240.Acidising 1241.General Acid may be squeezed to the formation by 'bullheading' or by using coiled tubing. The amount of fluids used are calculated as a volume per metre of perforated intervals. Normally, the stimulation consists of sequentially squeezing fluids into the formation:

1242.Pre-flush: 15% or 7.5% HCl Displaces water from and near the wellbore, dissolves calcareous formation material prevents the forming of insoluble calcium fluoride during the main treatment. 1243.Main flush: 12%/3% or 6%/1.5% HCl/HF HF reacts with clays, sand, mud and cement to improve permeability. HCl reduces HF precipitates. 1244.Post-flush: 2% NH4Cl, Methanol or Nitrogen Isolates main flush from brine, removes acid precipitates from near the wellbore, and restores the wettability of the formation. 1245.Pump pressure and rates Maximum pump pressure is defined as the maximum surface pressure prior to formation breakdown. It is a function of: fracture gradient, true vertical depth, fluid density, and tubular friction loss where:

Max. Pump Press. Where: FG TVD HH FL SF

= = = = = =

FG x TVD/10 - HH + FL - SF fracture gradient (bar/10) true vertical depth of interval (m) hydrostatic head of fluids (bar) friction loss in tubing (bar) safety margin(bar)

The fracture gradient of the formation is often unknown. In practice, an estimate from previous area experience is used. The friction loss is derived from computer programmes or charts. A viscosity of 1cp is generally assumed for acids. The safety margin is an arbitrary pressure to assure the reservoir will not be fractured. Generally, it is in the order of 20bar.

Maximum pump pressure dictates the maximum pump rate.

1246.Displacement In general, the main flush is either pumped +/- 1m from the wellbore or produced back immediately. When bullheading do not exceed the maximum calculated pressure. A common problem in matrix acidisation is the inability to inject fluid - the maximum pump pressure being reached with no injectivity. See Figure 15.2 for optional procedures.

1247.Post-acidisation clean-up Open the well and flow back spent acid at the maximum attainable flow rate. Following acidisation clean-up should occur as soon as possible. Take samples of spent acid. Continuously monitor the pH of the returns and store any returns with a pH < 5 in a separate tank.

Figure 1160.2 Decision tree (low injectivity)

1248.Fracturing The purpose of hydraulic fracturing is to create a highly permeable flow channel into the formation through. Either near wellbore formation damage or low reservoir permeability determines the frac length. Frac length determines the amount of proppant required and the volume of fluid required to carry the proppant. Typically, wells with near wellbore damage require short frac lengths and wells with low formation permeability require larger frac lengths.

In most instances oil or water are the base fluids used as a proppant transport medium. Where water is the principal base fluid, verify water purity with a turbidity meter. Where hydrocarbon fluids are to be used, pilot testing is of the utmost importance as contamination may destroy the ability of the fluid to gel properly. See 15.2.4 for frac fluids additives.

1249.Fracturing procedures Micro-Fracturing:

1250.Initially an Injectivity Test may be carried out to determine the ISIP (instantaneous shut-in pressure): the pressure observed immediately following shut-in. During this test the formation is fractured and pumping continues for a short period. The pumps are then stopped and the leak-off pressure observed. ISIP is equal to the bottom hole fracture pressure less than the hydrostatic pressure of the fluid column. 1251.The information obtained may be used to adjust the fracture programme. 1252.Prior to completion of an entire zone, selected areas may be perforated over a short interval for the purpose of injectivity tests. Mini-Fracturing:

1253.A small frac conducted with frac fluid and proppant prior to the main frac. 1254.The formation is fractured and frac fluid is pumped for ± 10 minutes. The pumps are then stopped and leak-off examined for ISIP, closure pressure, and leak-off rate. 1255.Based on these parameters the fracture programme may be adjusted. Main Fracturing:

1256.A large volume (40-70% of the total fluid volume) is pumped before any proppant is added to the base fluid. Its purpose is to open the fracture and propagate the fracture tip away from the wellbore. 1257.If too small a volume is pumped there is a risk of 'sand out' due to proppant reaching the tip of the fracture and preventing further propagation. 1258.Proppant is added in various stages increasing proppant concentrations. The concentration is increased as the fracture is propagating outwards. Too high a proppant concentration may cause screen-out within the fracture or at the perforations. 1259.Under-displace the flush leaving proppant at the perforations. 1260.The fracture should begin to close at the time when pumping terminates. Post-Fracture Procedures:

1261.In order for any fracture treatment to be successful, fracture closure must occur prior to the gel breaking. If closure does not occur prior to gel breaking the closure must be induced. Closure is induced by bleeding the well of at a very low rate. 1262.Monitor and record the wellhead pressure accurately. 1263.Following the shut-in period, the free depth of the well is checked with a wireline. 1264.Explosive proppant remaining in the frac string shall be cleaned out.

Contents

16. WELL EVALUATION AND PRODUCTION TESTING ..............................................XLVIII 16.1 Introduction ........................................................................................................XLVIII 16.1.1 Proof of minerals .........................................................................................XLIX 16.2 Production Testing Equipment .............................................................................XLIX 16.2.1 Equipment overview ....................................................................................XLIX 16.3 Equipment Description ...............................................................................................L 16.3.1 Xmas tree..........................................................................................................L 16.3.2 Surface safety valve..........................................................................................L 16.3.3 Data header .....................................................................................................LI 16.3.4 Choke manifold ................................................................................................LI 16.3.5 Heater ..............................................................................................................LI 16.3.6 Separator .........................................................................................................LI 16.3.7 Gauge tank......................................................................................................LII 16.3.8 Burner booms and burner heads ....................................................................LII 16.3.9 Surface piping .................................................................................................LII 16.3.10 Emergency Shut-Down (ESD) system ..........................................................LII 16.3.11 Sand filters ...................................................................................................LIII 16.4 Production Testing General Safety .........................................................................LIII 16.5 Potential Problems During Production Testing ...................................................... LIV 16.5.1 Liquid loading of gas wells ............................................................................ LIV 16.5.2 Hydrate formation.......................................................................................... LIV 16.5.3 Hydrate suppression .................................................................................... LVII 16.5.4 Treatment of hydrate plugs ......................................................................... LVIII 16.5.5 Hydrogen sulphide ...................................................................................... LVIII 16.6 Production Logging (Cased Hole Logging) ............................................................. LX 16.6.1 Introduction .................................................................................................... LX 16.6.2 Flowmeter spinner....................................................................................... LXIII 16.6.3 Continuous flowmeter tool (Schlumberger - CFS, Atlas - FMCS) ............... LXIII 16.6.4 Full bore spinner tool (Schlumberger - FBS, Atlas - FMFI) ......................... LXIII 16.6.5 Inflatable diverter tool (Schlumberger - IDT, Atlas - FMBK) ........................ LXIII 16.6.6 Fluid density tools ....................................................................................... LXIII 16.6.7 Gradiomanometer (Schlumberger - GMS) .................................................. LXIII 16.6.8 Pressure temperature sonde (Schlumberger - PTS, Atlas - FDDP)............LXIV 16.6.9 Nuclear fluid density tool (Schlumberger - NFD, Atlas - NFL).....................LXIV 16.6.10 Temperature tools (Schlumberger/Atlas - TEMP) .....................................LXIV 16.6.11 Manometer tools (Schlumberger - MTS/HMS, Atlas - SRPL) ...................LXIV 16.6.12 Strain gauges .............................................................................................LXV 16.6.13 Quartz gauges............................................................................................LXV 16.6.14 Water hold-up log (Schlumberger - HUM, Atlas - WHI)..............................LXV 16.6.15 Gamma ray (Schlumberger/Atlas - GR) .....................................................LXV 16.6.16 Casing collar locator (Schlumberger/Atlas - CCL) .....................................LXV 16.6.17 Compact production logging tool (Schlumberger)......................................LXV 16.6.18 Memory production logging tool ................................................................LXVI 16.6.19 Preparation procedures.............................................................................LXVI 16.6.20 Thermal decay time (Schlumberger - TDT, Atlas - PDK) .........................LXVII 16.6.21 Logging procedures .................................................................................LXVII Figures

Figure 16.1 Production testing process train ...........................................................................L Figure 16.2 Hydrate formation prediction.............................................................................. LV

Figure 16.3 Water content of natural gases......................................................................... LVI Figure 16.4 Temperature drop accompanying a pressure drop.......................................... LVII Figure 16.5 Production logging tool combinations .............................................................. LXII

1265.WELL EVALUATION AND PRODUCTION TESTING

1266.Introduction A well is production-tested to determine the production and reservoir characteristics of oil and gas. The objective of the test is to determine: 1267.Formation parameters; reservoir geometry, reservoir pressure and temperature. 1268.Formation performance parameters; production rate at 50bar drawdown, and skin factors. 1269.Fluid parameters; PVT fluid samples are taken for laboratory analysis. 1270.Well performance parameters; wellhead pressures versus flow rates to calculate deliverabilities. 1271.Flow contributions; production logging. All of the above parameters rely on the interpretation of pressures and flow rates. For this reason, it is essential that every effort is made to ensure that measurements are taken and recorded in as accurate a manner as possible.

Well testing will be performed by a selected, qualified contractor. A detailed well test programme shall be issued well in advance. The normal sequence of events during production testing is as follows: Perforate the well. Produce clean: to remove all completion fluids and debris from the well and establish a stable flow regime. Close in well: to allow the reservoir to equilibrate and initial pressure to be established before the production test begins. Downhole gauges are usually run during this period. Flow test: Generally a three-rate test for high rate gas wells (at 30%, 60% and 90% of the maximum rate achieved during the clean-up flow) is performed. For low rate gas and oil wells, a single rate may be sufficient. PVT samples are generally taken during this period. Build-up period: generally at least 1-1/2 times the total flow period. When using surface readout gauges the build-up will continue until sufficient information has been obtained. Production logging survey. Suspend or abandon the well.

1272.Proof of mineral. On some exploration wells it can be a requirement of the production licence to perform a flow period, carried out at the maximum rate.

1273. Production Testing Equipment 1274.Equipment overview The basic process train for production testing is as follows (see Figure 16.1): The formation fluids exit the well via the flow wing valve of the Xmas tree. The kill wing valve is connected to the kill pump. A check valve is installed in the 2" line. The fluids flow through the 3" surface piping to the choke manifold, passing through an emergency shut-down valve and the data header. At the data header, pressure and temperature parameters are collected and inhibitive chemicals can be injected. The fluid pressure at the choke manifold is allowed to drop in a controlled manner. Passing through the choke manifold causes cooling of gases. The fluids can be passed through a heater if hydrates are anticipated. An additional choke is incorporated in the heater for dropping the pressure in stages when hydrate formation is a real problem. The fluids are separated into gas, oil/condensate, and water at the separator. The gas is allowed to flow to the burner booms via an orifice meter. The gas can be directed to either boom at the gas manifold. Oil/Condensate flows to the oil manifold where it can be either directed to a gauge tank or flowed directly to the burner booms. The oil can be metered at the separator. Water is allowed to flow directly to the gauge tank. Fluids in the gauge tank can be transferred to the burner booms or a separate storage vessel via the oil manifold using a transfer pump. To optimise the burning mixture at the burner boom, the hydrocarbons can be mixed with air, from a dedicated compressor, and water from the rig pump.

Figure 1265.1 Production testing process train

1275.Equipment Description 1276.Xmas tree The solid block Xmas tree shall be used. Casing and tubing annulus pressure can be bled off to the process train via a T-piece connection on the flowline. Likewise, the well can be killed either by straight or reverse circulating through an identical T-piece connection on the kill side. The kill wing valve must always be left open during production testing in case of an emergency kill operation. The valves at the cement or kill pump unit are kept closed. A check valve is installed upstream of the kill side of the tree to prevent flowback from the well to the cement or kill pump unit, during kill operations. 1277.Surface safety valve A stand-alone, hydraulically actuated gate valve is included upstream from the choke manifold as part of the emergency shut-down system.

1278.Data header A data header (or instrument manifold) is installed directly upstream from the choke. It consists of a 3" diameter pipe section with several fittings for pressure/temperature monitoring and sampling. Pressure gauges should be fitted to the instrument manifold with double valve isolation. 1279.Choke manifold A 4-valve choke manifold (no central bypass) is used in Coparex operations. It comprises four gate valves with a positive, fixed bean choke between two of the valves and a variable multi-orifice or needle, and a seat type choke between the other two valves. Bleed off valves are located up and downstream from both chokes. The choke manifold must be rated to the maximum anticipated surface pressure, usually 690bars. 1280.Heater The heater serves to re-heat the produced fluids after a temperature decrease caused by the pressure drop over the choke. In gas wells this is most likely to prevent the formation of hydrates. Steam is ideally provided from a rig source, but can be provided by a stand-alone dieselelectric steam generator if required. The process coils are rated to 345bars minimum; steam coils and pressure vessel to only 150-200bars. A pressure relief valve and bursting disc are provided on the pressure vessel to vent off pressure in the event of process coil rupture. The heater incorporates a bypass manifold if there is no requirement to heat the produced fluids. 1281.Separator A horizontal 3-phase test separator can be used to separate the gas, oil/condensate and water phases from the produced fluids. Gas is metered by a senior orifice fitting on the discharge line. Ensure the gas meter is properly bypassed and vented when changing the orifice plate size during well flow. Oil/condensate and water are discharged by separate lines and metered by positive displacement turbines which can be bypassed. Oil/condensate is routed via an oil manifold either directly to the burner booms or to the gauge tank. Water is routed directly to the gauge tank. The maximum working pressure of the separator is 100bar. A safety relief valve set at 100bar and a rupture disc set at 110bar ensure that this pressure is never exceeded. The separator is normally the 'bottle-neck' in the processing train, determining the maximum throughput of the system, The capacity depends on where the liquid level is operating: 1282.High-level: up to 7 000 000m3/day gas and 2 070m3/ day liquids.

1283.Low-level: up to 1, 700 000m3/day gas and 795m3/day liquids. 1284.Gauge tank The gauge tank is open to the atmosphere and consists of two compartments, either 50bbl or 100bbl. When full, the contents are transferred by pump via the oil manifold to the burner booms. The transfer pump is an electrically-driven, explosion-proof centrifugal pump. Any additional gas, produced by the oil/condensate after the separator, is vented via the top of the gauge tank and a vent line hung overboard. The vent line contains a flame arrestor to prevent accidental combustion. 1285.Burner booms and burner heads Two burner booms on opposite sides of the rig are used to flare off hydrocarbons in order to reduce heat radiation. The air is provided by a dedicated compressor supplied by the test contractor. Water is provided from a rig pump, which also provides water to a “T-piece” located some 5m behind the burner head to provide an additional water shield against heat radiation. For safety, the oil, air, gas and water shall be supplied through check valves. 1286.Surface piping The pressure rating of the surface piping should be compatible with the rating of the downstream item of process equipment. The ID should be sufficient to maintain nonrestrictive flow of the process fluids, and should certainly never have an ID less than the largest choke size. The flowline from the Xmas tree to the cantilever deck ( for Jack-up rigs) shall be a 3" coflexip hose. This is connected to the test contractor's hard pipe at this point. All connections should be metal-metal “Weco" type, compatible with the pressure rating of the pipe and with the connections welded rather than threaded to the pipe sections. Temporary high-pressure pipework, such as Chicksans (3" 1502) is allowed for productiontesting applications. 1287.Emergency Shut-Down (ESD) system The ESD system consists of the following elements: 1288.The sub-surface safety valve. 1289.The upper hydraulically actuated master valve. 1290.The hydraulically actuated kill wing valve. 1291.The standalone surface safety valve with a hi-pilot between the heater and the separator. Each of the hydraulically activated, fail-safe valves above are controlled by an individual control panel. The control panels are powered from the rig air supply and they in turn hold

the safety valves open by hydraulic pressure applied via an oil-based hydraulic fluid. The valves are fail-safe to ensure closure when air is bled off. The fail safe valve activates with: 1292.A manual bleed off of air at the main control panels. 1293.A manual bleed off of air from the remote ESD stations. 1294.A leak or breakage of either the air supply or hydraulic lines. 1295.A tripping of the hi-pilot between the heater and the separator (stand-alone surface safety valve only). A double control panel is used for the combination of the master safety valve and the kill wing safety valve. This double control panel has two remote ESD stations, normally placed at the escape routes from the cantilever deck. The standalone surface safety valve has a single control panel with 3 remote ESD stations. Two are normally placed at the escape routes from the cantilever deck and a further one on the rig floor in the driller's doghouse. 1296.Sand filters Sand filters are recommended to be included in the flowline when excessive sand is expected or when cleaning up after hydraulic fracturing operations. They are rigged in upstream from the standalone surface safety valve and the choke manifold to prevent erosion.

1297.Production Testing General Safety All personnel on board shall be briefed at a general safety meeting. More than one meeting may be required to include shift personnel. The following points should be addressed: 1298.Review the station bill and personnel responsibilities for the test. 1299.Ensure that all personnel are aware that smoking is strictly forbidden outside the accommodation block. 1300.Identify the location of protective and emergency rescue equipment such as fire suits, breathing apparatus, stretchers and first aid equipment. 1301.Review emergency alarm signals and responses including abandon ship, fire, gas and man overboard. 1302.Emphasise that “hot work” permits must be obtained before commencing any work generating sparks or flames such as grinding, chipping or welding. 1303.Highlight any hazardous goods being handled during the test and discuss handling procedures. 1304.Describe the emergency shut-down (ESD) system, and in particular, point out the location of the remote shutdown points.

1305.Potential Problems During Production Testing 1306.Liquid loading of gas wells Liquid loading occurs in gas wells when there is insufficient gas velocity to lift water and/or condensate. As a result, water and/or condensate accumulates at the bottom, imposing additional backpressure which ultimately prevents the well flow. 1307.Hydrate formation Gas hydrates are crystalline solids formed by the chemical combination of natural gas and free water which can occur at temperatures significantly above the freezing point of water. Figure 16.2 shows that hydrates are dependent on the pressure, temperature and composition of the gas stream. Free water must be present for hydrates to occur. Hydrates do not occur in gas wells producing above the dew point. The formation of hydrates may choke or even block downhole equipment, surface lines, or surface test equipment. This can render equipment inoperable and can cause pressure to become trapped inside tools or lines, creating a potentially dangerous situation and often invalidating the test data. The most common areas for hydrate formation are downstream of chokes, control valves, orifice plates and needle valves used as sample points, which cause a sudden temperature drop along with a sudden pressure drop and the condensation of equilibrium water. The water content of natural gases and the temperature drop accompanying a given pressure drop are shown graphically in Figures 16.3 and 16.4, respectively. A secondary cause of hydrate formation is the introduction of water into the system when the surface temperature is relatively cold. This can occur during initial clean-up operations and when wireline lubricators are tested with water. For this reason it is recommended wireline lubricators are always tested with the available gas THP.

Figure 1265.2 Hydrate formation prediction

Figure 1265.3 Water content of natural gases

Figure 1265.4 Temperature drop accompanying a pressure drop

1308.Hydrate suppression The best way to prevent the possibility of hydrate formation is to keep the temperature of the gas stream above the temperature at which hydrates are expected to form. This is the primary function of the heater in the well test package. The

possibility of hydrates can be minimised by allowing the major system pressure drop to occur over the choke between the primary and secondary coils of the heater. Alternatively, where a severe hydrate problem exists, the heater can be placed upstream from the choke manifold. If insufficient heat can be maintained in the process system to avoid hydrate formation, the process stream has to be treated with an inhibitor, usually methanol or glycol. The inhibitor can be injected either at the Xmas tree or at the data header, upstream from the choke manifold (test contractor's pump). Inhibitor injection at the Xmas tree may continue for a short time after shutting in the well, thus allowing the inhibitor to fall down the tubing and prevent the formation of hydrates between the sea bed and the Xmas tree. 1309.Treatment of hydrate plugs If a hydrate plug occurs, the well should be shut in upstream from the plug, and the pressure bled off downstream, allowing the plug to dislodge. Pressure surging may occur as the plug moves downstream through piping, fittings, chokes, etc. If the plug will not dislodge through pressure reduction. Methanol or glycol should be injected. Dislodgement of plugs formed in surface facilities can be by applying heat externally to piping or fittings. The cause of hydrate formation should be analysed and remedial action taken, either in the form of additional heat or additional inhibition.

1310.Hydrogen sulphide 1311.General If unanticipated H2S is found to be present in a gas stream, the test should be terminated immediately. The Company Drilling Manager must be notified immediately. 1312.Test Equipment If H2S is present in a gas stream, it is essential to check that downhole and surface test equipment are sour service rated. All metals must meet the specifications in NACE MR-01-75 (latest edition). All elastomers must be compatible with H2S. No specific standards exist for elastometers. Where equipment cannot be positively identified as sour service, it must be treated as non-sour service. All safety relief lines will be routed to an area where discharge will present no hazards. A constant positive pressure (3.5bar) shall be maintained on the surge tank, and the vent line run to an area where the vented gas will not prove hazardous. 1313.Operational safety procedures The following precautions should be followed when H2S is known to be present: Prior to commencing the test, ensure all test contractor personnel have received training in H2S testing procedures.

Warnings signs should be posted and the testing area roped off. NOTE:

When H2S concentrations exceed 10ppm, only essential personnel should be out on deck, the remainder should remain within the accommodation, with doors sealed.

Testing personnel will adhere to the rig operators’ safety procedures. The testing area and other areas where a potential danger of H2S exists will be monitored with continuous gas monitoring equipment, using either fixed or portable monitors, with audible and visual alarms. The set point of these alarms should be 10ppm. Well test operators should also wear personal H2S monitors (e.g., Compur). There should be an adequate supply of H2S detector tubes (various ranges) on hand, to accurately measure the H2S concentration should a leak occur. Prior to commencing the well test, a safety meeting will be held to discuss operating procedures to establish hazardous areas, safe areas, escape routes, etc. Breathing Apparatus sets should be worn when venting H2S gas at concentrations greater than 10ppm. B.A. sets should be worn continuously for H2S concentration greater than 50ppm. If the concentration of H2S in the wellstream exceeds 100ppm, flaring should only take place during daylight hours. If the concentration of H2S exceeds 10 000ppm in the wellstream or 50ppm in air, the test shall be terminated immediately. Where the concentration of H2S in the wellstream exceeds 50ppm, the “buddy” system should be implemented. No H2S should be vented where it can accumulate. The wind direction should be monitored constantly. If a leak occurs, every effort should be made to eliminate the problem immediately. While flowing, all effluent should be sent to the burners. Flow periods should be limited to when the wind direction is suitable for carrying the gasses away from the selected burner and the installation. If there is no wind, then flaring should not be considered. If in doubt as to whether the well should be shut in, check H2S concentration around the boom; greater than 10ppm the well should be shut in. Every effort should be made to keep the flare alight at all times during flow periods. This can be done by leaving the propane pilot system running continuously. Any shrinkage measurements must be performed with the shrinkage tester in a well ventilated position, and B.A. sets must be used. 1314.Emergency procedures When an H2S alarm is activated, the following procedures should be followed by all personnel in the vicinity of the test package: Obtain a B.A. set/escape mask and mask up immediately. Warn other personnel in the area and leave immediately to a safe area, generally upwind and in an elevated position from the hazardous area. In the event of surface equipment failure the well shall be closed in immediately via the safety shut down system and surface process equipment shall be vented to zero pressure via the flare boom.

The rig floor and the radio room should be informed of the situation and an announcement made over the loudspeaker system warning all personnel to stay inside the accommodation block. Never enter an enclosed space or area where H2S may have accumulated without wearing B.A. sets. If a worker is over an arm’s length away, a safety belt should be secured to a life line and held by a responsible person in a safe area. Two test contractor personnel with air masks and B.A. sets (properly fitted and checked and air sufficient for 30 minutes) should investigate the source of the leak. One of these testers should be of a senior status. Lifelines should be worn and held by a responsible person in a safe area. The H2S levels should be checked with a Dräger tester while the investigation is ongoing. Once the source of the leak has been identified the appropriate remedial action shall be taken (shutting in the well if required). If the source of the leak cannot be identified, and the H2S concentration remains at a level which is considered unsafe for testing operations to continue, the test should be terminated. Bleed down surface process equipment to zero pressure via the flare. The system should be flushed, then filled with water and checked for the leaks. 1315.Carbon dioxide - explosive decompression One of the major problems encountered when dealing with high pressures is explosive decompression (ED). When seals are compressed under high pressure some gaseous elements diffuse into the seal. If a rapid pressure drop occurs or the pressure is frequently cycled, non-resistant materials may suffer extensive damage, usually in the form of splits and/or blister, due to expansion of the entrained gas against the elasticity of the rubber. This problem is especially prevalent where there is a high CO2 content in the well gas stream. If this is the case, ED may occur at relatively low pressures due to the ability of the CO2 to permeate the elastomers. The CO2 has no chemical affect on the elastomer, it is a purely physical phenomenon. The hardness of the elastomer and the level of fluorine in the elastomer have a major effect on the solubility of gas in the seal, and thus resistance to ED. The harder the elastomer seal the greater the resistance to gases permeating into it. The downside of this is that the harder the seal, the worse the sealing properties. Materials above 85 IRHD generally give greater resistance to ED. If ED is possible a great help in overcoming it is to bleed down slowly (if possible), as quite small differences in time to bleed off have a marked effect on the possibility of ED occurring.

1316.Production Logging (Cased Hole Logging) 1317.Introduction Production logging should ideally give information on both the production and reservoir engineering aspects of a well. Production logging provides downhole measurements of fluid parameters on a zone-by-zone basis yielding information on the type of fluid movement within and near the borehole.

Production logging tools (sensors), designed to measure the performance of production and injection wells is available. These sensors include: 1318.Flowmeter spinners (continuous, fullbore, diverter). 1319.Fluid density (gradiomanometer, nuclear). 1320.Thermometer. 1321.Manometer (strain gauge, quartz gauge). 1322.Radioactive tracer. 1323.Hold-up meter. These sensors can be run individually, or more commonly are run in combination. Recording is both real-time and simultaneous, measuring primarily: 1324.Fluid entries and exits. 1325.Standing liquid levels. 1326.Bottomhole flowing and shut-in pressures. 1327.Pressure losses in the tubing. 1328.Integrity of the gravel packs and hardware assemblies. Figure 16.5 shows a schematic of the sensors in a typical production logging tool string. The tool string also includes a casing collar locator and a gamma ray tool for correlation and depth control. A production logging survey can be recorded with the tool moving up or down. With the tool stationary measurements can be made versus time. Usually in a production well the down logs are most relevant. Conversely, with injection wells the up logs generally show the features most clearly.

Figure 1265.5 Production logging tool combinations For every flow rate and at shut-in conditions several passes are made, generally three passes in each direction at three different cable speeds. During each pass all parameters are measured simultaneously and the CSU system puts the reading on depth by compensating for the different positions of the sensors.

1329.Flowmeter spinner Flowmeter spinner tools are used to measure flow velocity. The spinner incorporates an impeller that is rotated by fluid moving relative to it. Size and pitch of the impeller selected will depend on flow rates expected. 1330.Continuous flowmeter tool (Schlumberger - CFS, Atlas - FMCS) The continuous flowmeter tool has an impeller mounted inside the tool. The most common tool diameter is 1-11/16 in. (although 2-1/8 and 2-7/8 are available). It is most often run in the tubing of high production or injection rate wells where the fluid velocities are high, usually in combination with the FBS. 1331.Full bore spinner tool (Schlumberger - FBS, Atlas - FMFI) The FBS tool is probably the most commonly run spinner tool. The tool collapses inside the tubing and opens inside the casing for logging. The accuracy and resolution of both the continuous and full bore spinners are very similar. However, the full bore tool can operate at lower velocities and is normally the preferred option. 1332.Inflatable diverter tool (Schlumberger - IDT, Atlas - FMBK) The inflatable diverter tool utilises a fabric diverter with an inflatable ring for use in medium/low flow rate wells. It is particularly suited for low flow rate measurement, e.g., water influx from a lower zone. It can be run in casing sizes up to 9-5/8" and there are three tool ODs, 1-11/16", 2-1/8" and 3". The 3" tool can operate in flow rates from 3m3/d to 190m3/d in 7" casing. 1333.Fluid density tools These tools measure downhole fluid density by establishing the density of each phase and that of the fluid mixture, the percent hold-up of each phase, and therefore its respective flow rate can be determined. Applications are: 1334.To provide accurate depth determination of pressure gradient changes. 1335.To locate gas entries in oil wells. 1336.To locate condensate entry in gas wells. 1337.To locate water entry in oil or gas wells. 1338.To define fluid contacts. 1339.To assist continuous flowmeter interpretation. 1340.Gradiomanometer (Schlumberger - GMS) The gradiomanometer tool uses the pressure differential between two bellows to infer the density of the fluid between the sensors. In deviated wells the reading must be corrected for

hole deviation by applying the cosine of the hole angle factor. Friction effects become significant above 350m3/d and are compensated for using the appropriate chart. 1341.Pressure temperature sonde (Schlumberger - PTS, Atlas - FDDP) The PTS is replacing the Gradiomanometer because of its better pressure resolution. It is also shorter and thus more convenient to use. It can only be used in deviated wells, and friction effects are negligible at normal flow rates. A density measurement is made by a strain gauge pressure transducer which measures the pressure differential between two ports. Wellbore pressure is transmitted to the differential pressure sensor via tubes filled with silicon oil. The tool also provides absolute measurements of temperature and pressure without having to use separate detectors. 1342.Nuclear fluid density tool (Schlumberger - NFD, Atlas - NFL) As with open-hole density tools, a GR source is emitted at the wellbore fluid which acts as an absorber. A high count rate indicates a low fluid density and vice-versa. Although not affected by either wellbore deviation or friction effects, this tool is sensitive to background gamma radiation and therefore rarely run. 1343.Temperature tools (Schlumberger/Atlas - TEMP) The varying electrical conductivity of a platinum wire that accompanies changes in ambient temperature is the basis of most temperature tools. The temperature log has many applications, particularly when run in combination with other sensors. Some of these applications are: 1344.Detection of gas production via the cooling effect of expanding gas (in or behind casing). 1345.Qualitative evaluation of fluid flow as indicated by departures from the geothermal gradient. 1346.Temperature information for PVT equations and charts. 1347.Evaluation of fracture treatments. 1348.Evaluation of the mechanical integrity of a completion. 1349.To locate fluid entries. 1350.To define lowest depth of production or injection. 1351.To determine bubble point depths. 1352.To check gas lift valves. 1353.To locate gas leaks in tubing. 1354.To define geothermal gradients. 1355.To locate fluid flow behind pipe. 1356.Manometer tools (Schlumberger - MTS/HMS, Atlas - SRPL) Measures downhole pressure with a surface readout. Two types of pressure gauge can be used - the strain gauge and the Hewlett-Packard crystal gauge. Some tool string

configurations incorporate using both the more robust but less accurate strain gauge acting as a back-up, to the less reliable but superior pressure measurement of the HP gauge. 1357.Strain gauges A strain gauge is included as part of either the temperature-manometer sonde or the PTS. This type of gauge is less prone to shock or vibration but can be subject to calibration drifts. 1358.Quartz gauges A separate quartz gauge can be included in a PLT string for more accurate pressure measurements. The disadvantage of the quartz type gauges is their temperature stability. Pressure stabilisation can take up to half an hour after a significant temperature change. They are also more sensitive to excessive vibration. 1359.Water hold-up log (Schlumberger - HUM, Atlas - WHI) A water hold-up indicator log provides a quantitative evaluation of the percentage of water occupying the borehole. The tool measures the electrical capacity of the wellbore fluids passing through it, and distinguishes between water and oil/gas. When oil and water densities are similar, the log may yield far more definition than conventional fluid density measurements. 1360.Gamma ray (Schlumberger/Atlas - GR) The natural Gamma Ray (GR) log is a recording of the total natural formation radioactivity. It can be recorded either in open-hole or in cased-hole, making it the primary tool for correlation and depth control between open and cased-hole logs. 1361.Casing collar locator (Schlumberger/Atlas - CCL) The casing collar locator is an integral part of most cased-hole logs. It records the magnetic effects of casing wall thickness and can therefore determine the location of casing collars. Its primary application is for correlation and depth control. 1362.Compact production logging tool (Schlumberger) The Compact Production Logging Tool (CPLT) is a combinable production logging tool replacing the normal PLT. Unlike the PLT which is run on mono cable, the CPLT had to be run on coaxial cable. Improvements over the PLT are: 1363.Improved telemetry capability through the use of a coaxial cable. 1364.Improved sensor accuracy; temperature effects of pressure measurements are compensate using built-in temperature sensors. Automatic downhole calibration of electronics whilst logging. 1365.Solid state accelerometer to give inclination and thus gradiomanometer correction.

Temperature, pressure and gradiomanometer are contained in the same sonde (CPLS). Accelerometer is present to measure motion and deviation of tool, used to correct gradiomanometer. Up to two flowmeters can be run simultaneously. CFS can be run anywhere in the tool string, where FBS has to be run at the bottom. If both are run CFS is placed close to FBS to take advantage of its centralisation. 1366.Memory production logging tool In cases where a PLT is required in single-phase flow, a slick line run PLT can be costeffective. The sensors run are a bi-directional spinner flowmeter, scintillation gamma detector, fast response external temperature sensor, and an optional high-resolution crystal or gap capacitance pressure gauge. Readings are taken every 2 seconds with a 32 000 data point memory capacity. Data is downloaded to a computer at the surface and analysis is then available within one hour. 1367.Preparation procedures General

The following guidelines should be met prior to logging: 1368.A production logging programme with final well completion diagram and deviation survey should be on site. 1369.Check tool size against ID of the nipples, and check the liner size of the basket spinner. 1370.Ensure the selected spinner is appropriate for the flow rates expected. 1371.The logging engineer plus winchman should have a well sketch with relevant depths and ID restrictions indicated. 1372.All production logging surveys should be preceded by a wireline dummy connected to HUD. 1373.Make sure well is clean before running a production survey (if necessary run a junkbasket). Flowmeters have been clogged by bits of wire, remnants of ceramic capsules or congealed mud. 1374.Ensure enough lubricator riser is on-site for the length of tool string. 1375.Ensure all pre-survey tool calibrations have been carried out and are within the allowable limits. 1376.Hold a safety meeting with all relevant personnel prior to rigging up. In consultation with the logging engineer calculate the weights required to avoid tool lifting based on expected flow rates, pressures and produced fluids (use appropriate charts or computer programme). Ensure sufficient sinker bars are available.

1377.Thermal decay time (Schlumberger - TDT, Atlas - PDK) The thermal decay time-log records the thermal neutron capture cross section of the formation by repeatedly emitting pulses of high-energy neutrons and measuring the thermal neutron rate of decay. Since chlorine is the strongest neutron absorber, the response of the TDT log is determined primarily by the chlorine present, i.e., sodium chloride in the formation (Cl- concentration being zero in gas and high in formation water). TDT logging identifies the presence of hydrocarbons in formations which have been cased and detect changes in water saturation during the production life of the well. The TDT log is useful for the evaluation of old wells, for diagnosing production problems, and for monitoring reservoir performance. TDT limitations are: 1378.No distinction between fresh water and oil. 1379.Quantitative results depend on knowledge of salinity, shale and porosity. 1380.Shallow depth investigation so wellbore invasion is a problem. 1381.Other thermal neutron absorbing elements exist, e.g., Boron, Iron, Lithium. 1382.Logging procedures The detector is calibrated using a special low power neutron source jig. The tool’s miniature neutron generator is not activated when at surface. When logging through tubing, care must be taken whilst running through nipples, etc. Record the HUD, do not run tool to this depth. Carry out main log and repeat section as per the logging programme. Check repeatability, ensuring they are basically identical, being aware that the formation can show the effects of bombardment from the main log. Ensure the correlation log (normally resistivity) and previous TDT logs are available on site. The shape of the decay time survey follows the shape of the open-hole deep resistivity log. When correlating with GR, tie in with neutron source in “off” position to avoid unnecessary irradiation. The logging speed is normally 900ft/hr.

Contents

17. REMEDIAL CEMENTING.................................................................................................III 17.1 Introduction ...............................................................................................................III 17.2 Squeeze Cementing..................................................................................................III 17.2.1 Slurry design specials ......................................................................................III

17.2.2 Injectivity test....................................................................................................III 17.2.3 Pressures .........................................................................................................III 17.3 Squeeze Methods .....................................................................................................III 17.3.1 Bradenhead (no packer) ..................................................................................III 17.3.2 Circulation squeeze......................................................................................... IV 17.3.3 Block squeeze................................................................................................. IV 17.3.4 Hesitation squeeze.......................................................................................... IV 17.3.5 Remedial cementation - shoe tracks................................................................ V 17.4 Remedial Cementing................................................................................................. V 17.4.1 Cement plugs for remedial cementing ............................................................ VI

1383.REMEDIAL CEMENTING

1384.Introduction Remedial cementing applications: 1385.If primary cementation has failed. 1386.To eliminate water/gas intrusion. 1387.Repairing of casing leaks. 1388.Abandoning of old perforations or plugging off depleted zones. 1389.Curing lost circulations. 1390.Sealing off of formations giving well control problems.

1391.Squeeze Cementing For cement products and main slurry design, see Section 11, Cementing of this manual. The reduction of the hydrostatic head whilst hardening of cement should be kept in mind. 1392.Slurry design specials 1393.Fluid loss control agents ensure that no bridging of cement occurs due to dehydration of cement. 1394.Friction reducers facilitate good penetration of the slurry. 1395.Retarders are necessary for long squeeze jobs, particularly hesitation squeezes. 1396.Injectivity test 1397.Make an injectivity test prior to spotting the cement slurry. 1398.Injectivity of approximately 0.16 cu.m/min. is normally required to squeeze off perforations and higher rates for cement bond repairs. 1399.Perforations cannot be squeezed off successfully when large losses are being experienced. 1400.Care must be taken to prevent the blockage of perforations with L.C.M. 1401.Pressures 1402.All surface pressures are to be recorded. 1403.It is good practice to hold backpressure on the annulus above the cement retainer. 1404.The formation fracture pressure not to be exceeded.

1405.Squeeze Methods 1406.Bradenhead (no packer) 1407.R.I.H. to bottom of perforations.

1408.Circulate on bottom. Check well is static. 1409.Set "Balance" plug of required volume. 1410.P.O.H. until stinger is +/- 100m above theoretical T.O.C. 1411.Reverse circulate well clean. 1412.Close BOP's on drillpipe. 1413.Squeeze via the string. 1414.Circulation squeeze Used on primary cement repair jobs where circulation cannot be established.

1415.Perforate above and below the zone to be cemented. 1416.R.I.H. with bridge plug on drillpipe. 1417.Set bridge plug between perforations. 1418.Circulate casing/hole annulus, clean (calculate casing collapse pressure). 1419.Unsting from bridge plug and circulate hole clean. Spot a high vis pill. Sting into bridge plug. Circulate/squeeze cement around perforations as per programme. 1420.P.O.H. until stinger is above theoretical T.O.C. and reverse circulate out any cement. 1421.Bradenhead squeeze cement into top perforations (do not over-displace). 1422.If unable to establish circulation block squeeze lower perforations and Bradenhead top perforations. 1423.Block squeeze 1424.Used on primary cementation repairs where it is difficult to establish proper circulation over the entire section. 1425.The repair includes a number of squeezes through cement retainers. 1426.Hesitation squeeze 1427.Used to obtain a more uniform fill when squeezing off perforations. 1428.Performed in the same way as the Block squeeze with the exception that the squeeze period is devided into alternate squeeze and shut-in periods. 1429.Different perforations (in the same zone) will have different injectivities. On the first squeeze the perforations with the highest injectivity will accept cement. Further squeezes will begin to fill perforations with less injectivity until the zone becomes plugged-off. Do not initially exceed formation breakdown pressure during squeezing. 1430.R.I.H. to bottom of required squeeze zone. 1431.Circulate and ensure well is static. 1432.Set balanced cement plug as per programme. 1433.P.O.H. until stinger is +/- 100m above theoretical T.O.C. 1434.Reverse circulate well clean.

1435.Close BOP's on drillpipe. 1436.Squeeze via string as follows: 405.Increase drillpipe pressure until a leak-off is observed (It is not the intention to fracture the formation or inject the pumping fluid). 406.Hold for a minimum of 5 minutes, or until a leak-off is observed. 407.Repeat pressure build up and hold phases until 20% of original plug volume remains in the casing or the maximum allowable surface pressure (to be set by Rig Manager) has been achieved. 408.Hold 85% of initial leak-off pressure on drillpipe for a minimum 5 times the tested slurry setting time. While holding backpressure circulate at 0.2m3/min. for 5 min. every half-hour to ensure string remains free. 1437.Remedial cementation - shoe tracks In the event that the shoe is not properly cemented to provide hydraulic isolation, then secondary cementing is required:

1438.Clean out rathole to original depth. 1439.Attempt circulation around the shoe track. Monitor the returns up the annulus to check if losses are occurring. Prior to cementing a rate greater than 0.1m3/min. is advised. If necessary, circulate to clean or establish channels in the existing cement sheath. Consider the use of fresh water, or acid to attain sufficient rates. The acid should be specially formulated to improve communication into the open hole annulus (HF/HCL). Acid must be inhibited to prevent casing damage. Consideration should be given to the type of formation being acidised as H2S may be produced caused by acid/formation reaction. 1440.Consider setting a cement retainer above the shoe. In larger casings, displacing to cold drill water or sea water may cause the casing to contract slightly, improving the possibility of cementing off micro-annuli. 1441.If unacceptable rates are attained, a cement evaluation log should be run to assist in selecting an appropriate perforation depth. Acidising may be required to initiate or improve the circulation. 1442.Depending on the circumstances, a hesitation, block, or circulation squeeze can be attempted.

1443.Remedial Cementing The success of all cement squeeze operations is dependent upon quality control of the cement properties and proper implementation of the specified procedures. In order to ensure the success of the cementing operations, the following procedures should be followed prior to mixing the slurry on location:

Pilot test the cement in the cementing contractor’s laboratory with a representative sample of mix water to determine thickening times and additives required to produce the specified fluid loss. NOTE:

The recommended fluid loss for squeeze cementing should be between 50 and 150cc/30 min. at a differential pressure of 70bar through a 325 mesh screen.

Ensure that all mixing and displacing equipment is clean. Chloride and/or magnesium contamination of the cement may result in very short thickening times. The following parameters should be checked prior to pumping the slurry:

409.Measure the required mix water into a tank. The required volume of slurry will be specified in the completion programme. 410.Add the required amount of fluid loss polymer and/or retarder to the water and mix thoroughly. NOTE:

Batch mixing is required.

411.Obtain samples of the mix water and dry blend and retain until the well operations have been terminated. 412.Re-check displacement calculations prior to pumping. 413.Once the slurry has been pumped and the lock-up pressure has been achieved, the well is to be shut in while WOC. 414.The WOC time should be as programmed. Compressive strength of the cement is not an overly critical parameter in squeeze cementing, as the cement acts more as a plugging agent. Testing the Squeeze 415.Apply pressure over the squeezed perforations. The test pressure will be specified in the drilling programme. 1444.Cement plugs for remedial cementing 1445.Cement plugs can also be used for remedial cementing. 1446.Cement plugs shall be tailor-made for the job by the cementing contractor (see Section 11, Cementing).

Contents

18. SUSPENSION AND ABANDONMENT .............................................................................9 18.1 Introduction ................................................................................................................9 18.2 Well Termination ........................................................................................................9 18.2.1 General .............................................................................................................9 18.2.2 Abandonment....................................................................................................9

18.2.3 Suspension .......................................................................................................9 18.3 Abandonment Techniques .......................................................................................10 18.3.1 Shut-offs..........................................................................................................10 18.3.2 Fluids...............................................................................................................10 18.4 Abandonment Guidelines.........................................................................................11 18.4.1 General ...........................................................................................................11 18.4.2 Integrity tests...................................................................................................11 18.4.3 Open-hole plug back .......................................................................................11 18.4.4 Liner shut-off ...................................................................................................12 18.4.5 Casing stubs plug back ...................................................................................14 18.4.6 Perforated casing plug back............................................................................15 18.4.7 Permanent packer...........................................................................................15 18.4.8 Retrievable packer ..........................................................................................15 18.4.9 Surface plug shut-off .......................................................................................15 18.4.10 Annular spaces .............................................................................................17 18.4.11 Accepted practices........................................................................................17 18.5 Cutting Techniques ..................................................................................................18 18.5.1 Casing cutting .................................................................................................18 18.5.2 Conductor cutting ............................................................................................19 18.5.3 Stabilisation.....................................................................................................19 18.5.4 Equipment .......................................................................................................19 18.5.5 Problems with cutting ......................................................................................20 18.6 Mud-line Suspension Hanger...................................................................................20 18.6.1 DrilQuip MS-15 system ...................................................................................20 18.6.2 Abandonment..................................................................................................21 18.6.3 Suspension .....................................................................................................21 18.6.4 Tie-back phase................................................................................................24 18.6.5 Stab-in tie-back tools.......................................................................................24 18.6.6 Temporary abandonment ................................................................................24 18.7 Final Well Status ......................................................................................................26 Illustrations

Figure 18.1 Uncased borehole shut-off options .....................................................................13 Figure 18.2 Liner shut-off options ..........................................................................................14 Figure 18.3 Perforated casing shut-off options ......................................................................16 Figure 18.4 Surface plug shut-offs.........................................................................................17 Figure 18.5 Well abandonment..............................................................................................22 Figure 18.6 Well suspension..................................................................................................23 Figure 18.7 Conductor protection dome ................................................................................25

1447.SUSPENSION AND ABANDONMENT

1448.Introduction The basic guidelines for suspension and/or abandonment of boreholes are provided by company policy.

1449.Well Termination 1450.General The two methods of plugging back are: 1451.Abandonment. 1452.Suspension (Temporary Abandonment). Improper abandonment may result in gas migration to surface, influxes into depleted pay zones, supercharging formation pressures, etc. which can necessitate re-abandonment or relief well drilling. The main requirements of well suspensions are: 1453.To leave the well in a safe condition downhole, such that if the wellhead is accidentally damaged or removed, the well will retain pressure integrity and will not flow. 1454.To allow the well to be re-entered at a subsequent date and a BOP installed without recourse to repair work. 1455.To leave the seabed around the wellhead clear of drilling-related debris. In general, exploration, appraisal or development wells may be abandoned or suspended for various reasons. See 18.2.2. 1456.Abandonment The following are reasons to abandon a well: 1457.Drilled as a dry hole. 1458.Depleted, or uneconomic to produce. 1459.Mechanically unacceptable (badly corroded wellheads, collapsed pipe, unrepairable leaks, etc.). 1460.Uncommercial quantities of hydrocarbons or water found. 1461.Unexpected pressure regimes exceed the casing design. 1462.Unacceptable annulus pressures due to gas ingression. 1463.Suspension Well suspensions are a result of: 1464.TD not being reached due to environmental reasons, seasonal restrictions, abandonment pressure, installation repair, etc.

1465.The well has been successfully drilled but has not been fully tested for commercial, budgetary or strategic reasons, etc. 1466.The well has been drilled, tested, and may possibly be required in the future as part of a field development (i.e., temporarily abandoned). 1467.The well has been pre-drilled through a template to be tied back at a later stage as part of an offshore platform development. 1468.The well was found to be a dry but a potential candidate for side-tracking. 1469.Re-entry is planned, to recover downhole gauges (hung-off for long-term build-up analysis, or interference testing). 1470.Temporary suspension of a platform development well or subsea template well to skid rig over and kill a problematic producer. 1471.The well has been drilled with an MLS system and suspended, to be re-entered later for subsequent production as a single well jacket/installation; or possibly to become part of a template development, from which further directional production wells can be drilled.

1472.Abandonment Techniques 1473.Shut-offs Cement

Cement is the preferred means of abandonment since it can withstand high differential pressures and does not corrode or deteriorate with time. Mechanical

Mechanical plugs are used below cement plugs: 1474.To support the cement plug. 1475.To prevent gas migration while cementing. Commonly used mechanical plugs are: 1476.Bridge plug and cement retainers (converted to bridge plug). 1477.Production packer with a wireline plug set in tail assembly. 1478.Through-tubing bridge plug (TTBP) with cement bailed on top (for partial abandonments only). 1479.Fluids Abandonment fluids, either mud or brine, are complementary to the mechanical plug, see 18.3.1. In special cases, squeezing salts or settled solids may be accepted as shut-offs. In such cases in-flow testing or a long observation period would be mandatory

1480.Abandonment Guidelines 1481.General The following are general abandonment guidelines: 1482.Fluids left in the hole should be a high enough SG to withstand any expected pressure, plus a 0.05SG safety margin. 1483.Fluids left in the casing annuli are to be treated with biocide and corrosion inhibitor. Any fluids left across potential productive zones must be non-damaging. Oil-based mud systems are exempt. 1484.Permeable formations of different geological ages are normally isolated by cement plugs. 1485.Formations having different pressure regimes are isolated from each other. 1486.Silica blend cement is used where temperature effects may cause long-term degradation of neat, class G cement. 1487.If the well has been tested, the test intervals will be isolated by using cement or bridge plugs, or a combination of both. 1488.Should a mechanical plug be exposed to fluids containing H2S or CO2, then a 50m cement plug must be placed directly on top. 1489.When cutting casing, the shoe strength must be high enough to withstand the mud hydrostatic. The mud weight in the hole should have a minimum 15bars overbalance over the formation pressure with the riser removed. 1490.It is company policy that all casing strings are cut a minimum distance below their datum point, i.e., 3.0m below mud-line. 1491.For temporarily abandoned wells, a corrosion cap must be installed. 1492.Integrity tests All cement or mechanical isolation plugs, excluding plug at surface, should be weight-tested to 10-15 T and/or pressure-tested to 50bars/15mins. It may be necessary to perform an inflow test. This may entail displacing the well partially to nitrogen to achieve sufficient underbalance. If a plug has been set in stages not separating different zones, locate only the top of the last stage. Do not set more than 2 x 150m cement plugs without tagging TOC and establishing presence of plugs. 1493.Open-hole plug back In a dry borehole (see Figure 18.1), place a 100m cement plug above the last casing shoe, or set a mechanical bridge plug above the shoe and dump a 2m cement cap on top. In a potentially productive borehole, hydrocarbon and water-bearing zones must be isolated: 1494.Single zone:

416.Place a cement plug across its entire length plus 100m above the producing zone. 1495.Multiple zones: 417.Place a 100m cement plug between each zone, or one equal to their separation distance if less than 100m. 1496.Liner shut-off If a cemented liner has been run, a shut-off must be placed on top to isolate the liner lap. Several shut-off options are available (see Figure 18.2) as follows: 1497.Place a cement plug across the liner top that extends 50m either side, or; 1498.Set a mechanical plug 10m ± below the liner top with a 60m cement plug placed on top, or; 1499.Set two mechanical plugs above and below the liner top. Dump a 2m cap of cement on top of each bridge plug, or; 1500.Provided there is no communication between reservoirs via the liner top, set a mechanical plug directly above, with a minimum 2m cement cap.

Figure 1447.1 Uncased borehole shut-off options

1501.Casing stubs plug back If a casing string is to be partly recovered, a shut-off must be placed at the depth of the cutoff point. The guidelines in 18.4.4 apply also for casing stub shut-offs.

Figure 1447.2 Liner shut-off options

1502.Perforated casing plug back It is mandatory for perforations to be covered with cement when abandoning a well. The regulations that apply are as follows (see Figure 18.3): 1503.Single zone: 418.Place a cement plug which extends at least 50m above the perforated interval, 419.Set a mechanical plug as close as possible, with a 2m cement cap on top, 420.Squeeze off the perfs through a mechanical plug set above, and spot a 2m cement cap on top. 1504.Multiple zones: 421.As per open hole regulations (see 18.4.3) 1505.Permanent packer Mill the packer, run a tubing stinger below the lowest perforation and plug back over the perforated interval using the hesitation squeeze method. Run a stinger through the packer below the lowest perforation and plug back over the perforations, and hesitation squeeze away cement. This method should be considered only when the bore of the packer will allow a generous flow area for circulating and cementing. Run an EZSV, or equivalent, on wireline and set 50m above top perforation. Run an EZSV stinger, stab in, and squeeze away the cement, leaving the TOC 15m below the EZSV. This method shall be considered only if a good injection rate was established while killing the well. 1506.Retrievable packer Pull the packer out of the hole, run a tubing stinger below the lowest perforation and circulate cement over the perforations and perform a hesitation squeeze. 1507.Surface plug shut-off A shut-off should be placed as close as possible to the cut-off point (see Figure 18.4), consisting of either: 1508.A cement plug of at least 100m. 1509.A mechanical plug with at least a 50m cement plug on top.

Figure 1447.3 Perforated casing shut-off options

Figure 1447.4 Surface plug shut-offs 1510.Annular spaces Where a potentially productive formation exists behind casing which is not cemented off, it will be necessary to isolate the interval, by squeezing or circulating cement behind the casing. A minimum 100m cement column should be placed as close as possible to the previous casing shoe. If the formation is known to be at normal gradient and has no hydrocarbon content then this will generally not be required. Alternatively, the casing string may be cut deep and a cement plug set across the cut, see 18.4.4. 1511.Accepted practices Use a calliper log to calculate the required volume of cement slurry for each plug. If a calliper is not available, then use the open-hole volume, plus 20% excess. Gauge hole sections are preferable when setting cement plugs. Experience shows that when a cement plug is set in washed out sections, the cement bypasses the mud, resulting in an extended cement column giving rise to heavy back-flow, and the plug is likely to be of poor quality. If it is necessary to set a plug in a washed-out interval, then it is recommended that two short plugs be used rather than one long, large-volume plug. When setting abandonment plugs in potential loss zones, it is best to set the plug in two stages - i.e., a small plug first, which after hardening acts as a support base for the remaining length of the plug.

Use 23/8" or 27/8" tubing stinger to set critical cement plugs in 81/2" hole. Where small amounts of cement are required the slurry should be batch mixed tank prior to displacement to ensure that it is homogeneous, and set by the “running” method. Never stab the stinger back into a plug after displacement as the setting cement may plug the stinger. Whenever possible, neat slurries without additives, shall be used for plugging back. It is good practice to use mix water spacers ahead and behind the slurry. Adequate volume should provide a 50m spacer inside the displacement behind the cement string and 50m in the annulus. Always calculate the loss of hydrostatic head when using water ahead of a plug and reduce the water spacer as required, but retain approximately 50m of water as a minimum spacer.

1512.Cutting Techniques There are two basic methods available to cut casing, mechanical or explosive. The choice will largely depend on water depth and past experience. Recently, mechanical cutting has become more reliable due to improved cutter technology and to Quality Assurance inspection, resulting in fewer equipment failures. Either of these two methods is acceptable. At intermediate depths, modern cutting methods have a high probability of success and will be the preferred option. From a safety and environmental aspect, the mechanical method is the preferred method. 1513.Casing cutting Recovery of intermediate and smaller diameter casing strings is usually straightforward. Recovery of the 30" and 20" pipe is somewhat problematic. If 7" is tied back to surface, the cut is approximately 1 000m below the mud-line using a flash cutter on wireline or mechanical cutter on D.P. The 95/8" casing is normally mechanically cut 500m below the mud-line. The 133/8" casing shall be cut mechanically 150m below the mud-line.

Cutting assemblies for the above casing sizes are:

NOTE:

Casing Size (“) Cutter Size (“) 7 5 3/4 5 81/4 9 /8 (*) 3 13 /8 113/4 20 113/4 113/4 30 3 5 * The larger 5 /4" cutters are required for heavy-wall 9 /8" (i.e., 53.5ppf).

If using explosive or chemical cutters, ensure that safety precautions are strictly adhered to.

1514.Conductor cutting Care should be exercised in all aspects of the operation. The recovered, undamaged wellhead can be reused resulting in substantial savings. The overriding consideration is to minimise external or internal damage of the wellhead joint, for re-use with minimal refurbishment costs. If damage to the wellhead is severe, its pressure rating may be downgraded following repairs or scrapped. Care should be exercised when cutting. An unsuccessful cut can jeopardise abandonment operations, leading to increased costs. To prevent excessive wellhead damage, abandonment tools and techniques have been developed to reduce contact between the wellhead, its internal profiles, and the cutting/pulling assemblies. Cutting in tension is the established practice. A successful cut is readily noticed as a reduction in overpull. The 20" and 30" casing pipe shall be cut a minimum 3m below the mud-line. 1515.Stabilisation When the casing cutter is stabilised above and below the cutting knives the possibility of offcentre cutting is reduced resulting in faster cuts. Drift-sized stabilisers should be utilised. If the casing design includes a swaged diameter below the wellhead, a stabiliser should be included in the reduced diameter section. Measure the minimum diameter of the wellhead when gauging stabilisers for the cutting assembly. Stabiliser blades should be of the non-rotating type, tapered at the top and bottom. Blades can have a thin "skin" of brass or similar material brazed onto their leading edges. This acts as a sacrificial layer when the stabiliser is passed through the sealing bore areas of the wellhead reducing contact damage. 1516.Equipment The main components of wellhead cutting/pulling string are, top down: 1517.HWDP (to surface) 1518.DCs (6 x 8") 1519.Bumper Sub (optional) 1520.Catch Assembly (usually rotating spear) 1521.Stabiliser (17½") 1522.Pipe Cutter (usually 4 bladed 113/4") 1523.Stabiliser (17½") 1524.Bullnose (with circ ports).

1525.Problems with cutting If casing removal is unsuccessful: 1526.Trip the cutting assembly and inspect the knives to ensure they have been cutting at their maximum diameter. 1527.If both casings have been cut satisfactorily but the wellhead cannot be removed, consider running a fishing assembly to jar the wellhead and casing free. 1528.Economics may dictate the running of an explosive charge rather than a fishing assembly. Poorly cemented or uncentralised 20" will have a tendency to move when cutting the 30". Off-centre cutting may occur, resulting in the 30" being partially cut on one side only. If pulling and cutting is unsuccessful unlatch the spear and pull the cutting assembly for inspection. If any special 20/30" casing centralisers were run, the cut must be at least 2m above or below the centraliser. If both casings have been cut, a cement sheath around the conductor may prevent the casing from coming free. Before running a spear to retrieve the casings (wellhead and guide bases) an explosive charge may be run to fracture the cement sheath. Cutters can be run with a “flo-tel” device which indicates a pressure decrease when the knives have reached their maximum cutting diameter. The decision to stop cutting should not be made on the basis of a pressure drop alone. Problems can occur when attempting to release the spear or grappling mechanism. Knives can become jammed in the cut pipe, making it difficult to release the spear. A bumper sub can be run in the assembly between the pipe cutter and spear, allowing the spear to travel down the length of the bumper sub stroke, releasing it. However, a bumper sub placed in this position introduces a weak point in the assembly. Uncemented casing can be problematic with right-hand cutting action inducing left-hand torque into the joints above causing possible back off. Having a cement sheath is advantageaus but if not uniform cutting performance and efficiency can be affected.

1529.Mud-line Suspension Hanger Mud-line suspension (MLS) equipment, generally used in jack-up drilling operations, allows for the recovery of concentric casing strings at the mud-line by backing off once the well has been abandoned or suspended. 1530.DrilQuip MS-15 system The DrilQuip MS-15 - mud-line suspension system is designed for a 36/30/28" x 18.788" x 133/8" x 95/8" x 7" stack-down wellhead. The principle features are: 1531.Each mud-line shoulder hanger is equipped with an LH running thread and an RH tieback thread. 1532.Both the running and tie-back threads have a dedicated metal-to-metal seal area which mates up with the respective running or tie-back tool.

1533.All hangers stack down, fully exposing the tie-back, thread and seal areas for potential tie-back. This arrangement also allows for sequential capping of each string during well suspension, such that all TA caps are completely covered by the next outer cap. 1534.Whether a well is to be suspended or abandoned, retrieval of all but the 30" hanger is possible. Since the 30" hanger is butt-welded to conductor pipe, it is either cut off below the ML if abandoned, or above it if suspended. 1535.Tie-back tool seals also isolate both thread forms when installed in the mud-line hanger, preventing corrosion and marine growth from interfering with threaded connections. 1536.Abandonment If a well is to be abandoned, as shown in Figure 18.5, cement plugs will be set in accordance with the guidelines, see 18.4, and the 30" is cut a minimum of 3m below the mud-line. 1537.Suspension If a well is to be suspended, see Figure 18.6, TA caps will be installed on all successive casing strings. TA caps can be either the threaded type or stab-in type. The inner-most cap contains a backpressure valve for containing well pressure, with monitoring and release through D.P. All TA caps utilise the running threads in the hanger (i.e., installed with LH rotation, retrieved with RH rotation), protecting the tie-back threads.

Figure 1447.5 Well abandonment

Figure 1447.6 Well suspension

The conductor will be cut 1-1.5m above the mud-line and a dome placed on top with reflectors for positioning purposes on re-entry. Gravel may be judiciously dumped around the suspended wellhead, without burying it, as protection against scourings.

1538.Tie-back phase Threaded Tie-back Tools Where a well has been identified or designated for tying-back, two methods are available. The first option utilises the tie-back threads, the second relies on stab-in technology. The threaded tie-back option is RH (6 turns) to make-up, and uses a metal-to-metal seal plus two resilient seals to contain internal pressure. Two additional resilient seals contain external pressure. The threads are a self-aligning square form design on the DrilQuip tie-back tool, to prevent cross-threading for remote make-up. 1539.Stab-in tie-back tools Straight stab-in automatically locks into the hanger tie-back threads, with full engagement of resilient seals. The same sealing arrangement is used on the stab-in tool, as that used on the tie-back tool. An internal landing prep and torque slot is incorporated so that a torque tool, run on drill collars or drillpipe, can be used to energise the m-t-m seal, eliminating torque on the tie-back riser connections. The stab-in tool is weight-set for make-up and rotated (1/2-1 RH turn) to energise the metal seal. 1540.Temporary abandonment Check all annuli for pressure before nipping down the BOP stack.

Starting with the last casing string, remove the slip-and-seal assembly and latch onto the casing with the spear. Pull sufficiently to achieve neutral weight at the mud-line, then back out the running tool by turning to the right. Repeat the above for each casing string in turn. After recovering the 20" running string, a corrosion cap should be installed in the 20" hanger. Install the extended stinger below the corrosion cap and engage the J-slot running tool. Check that the stinger in the running tool opens the check valve in the corrosion cap by pouring water through the assembly.

Figure 1447.7 Conductor protection dome Land in the hanger and make-up with LH turns. Check that the string moves down 1" per turn. Release the running tool from the corrosion cap, and unseat the check valve for recovery allowing the hose to break. Disconnect the 30" conductor at the mud-line and recover. Run and latch the 30" dome cap onto the well, using either a hydraulic-operated or J-slot running tool. Dome shapes are usually round but can be hexagonal (see Figure 18.7).

NOTE:

The free water depth above the dome shall be in accordance with the approved abandonment programme.

1541.Final Well Status After a well has been abandoned or suspended, it is a requirement that the following information is documented: 1542.Dome and running tool type, dimension, height above seabed, and any special operations. 1543.Quantity of gravel dumped on top of the dome (typically 25-50 tonnes). State whether an ROV was used to monitor, assist or direct the operation. The above information shall also be filed in the Company Well Data File.

Drilling Manual

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