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.

•

One line towards the starboard side of the rig.

•

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.

•

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.

•

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.

•

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.

•

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

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

2. B.O.P. EQUIPMENT

2.1 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.

2.2 Diverter Systems 2.2.1 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.

2.2.2 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.

•

One line towards the starboard side of the rig.

•

One line to the flowline.

The diverter system should incorporate a kill line complete with a check valve. 2.2.3 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.

•

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.

•

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.

•

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.

2.3 Large bore (21¼”) BOP stack (flanged connections) 2.3.1 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.

2.3.2 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.

2.4 Small bore (13 5/8”) BOP stack (flanged connections) 2.4.1 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 2.1

Large bore 211/4” BOP stack

•

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

•

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

The small bore configuration is shown in Figure 1.2.

Figure 2.2 Small bore 135/8” BOP stack 2.4.2 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.

2.5 BOP Stack Control System 2.5.1 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.

2.5.2 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.

2.6 Choke manifold (flanged connections) 2.6.1 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”.

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

Figure 2.3 Choke manifold layout 2.6.3 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 2.4 Kill and choke manifold

2.7 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.

2.8 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.

2.9 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.

2.10 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 2.5 Stripping set-up

2.11 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 2.6 Surge bottle set-up For stripping the drillstring has to be equipped with an R.H. Kelly cock and a “Gray” valve (check valve).

2.12 Additional Well Control Equipment 2.12.1 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.

2.12.2 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.

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

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.

2.12.4 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 2.1 Well control equipment check

Form 2.2 Weekly well control inspection

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

3. B.O.P. EQUIPMENT

3.1 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.

3.2 Diverter Systems 3.2.1 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.

3.2.2 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.

•

One line towards the starboard side of the rig.

•

One line to the flowline.

The diverter system should incorporate a kill line complete with a check valve. 3.2.3 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.

•

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.

•

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.

•

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.

3.3 Large bore (21¼”) BOP stack (flanged connections) 3.3.1 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.

3.3.2 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.

3.4 Small bore (13 5/8”) BOP stack (flanged connections) 3.4.1 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 3.1

Large bore 211/4” BOP stack

•

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

•

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

The small bore configuration is shown in Figure 1.2.

Figure 3.2 Small bore 135/8” BOP stack 3.4.2 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.

3.5 BOP Stack Control System 3.5.1 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.

3.5.2 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.

3.6 Choke manifold (flanged connections) 3.6.1 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”.

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

Figure 3.3 Choke manifold layout 3.6.3 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 3.4 Kill and choke manifold

3.7 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.

3.8 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.

3.9 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.

3.10 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 3.5 Stripping set-up

3.11 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 3.6 Surge bottle set-up For stripping the drillstring has to be equipped with an R.H. Kelly cock and a “Gray” valve (check valve).

3.12 Additional Well Control Equipment 3.12.1 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.

3.12.2 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.

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

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.

3.12.4 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 3.1 Well control equipment check

Form 3.2 Weekly well control inspection

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.

•

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.

•

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.

•

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.

•

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.

•

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.

•

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).

•

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.

•

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.

•

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.

•

Three minutes to have the well shut in.

•

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.

•

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.

•

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.

•

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".

•

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.

•

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.

•

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.

•

Maximum allowable casing pressure.

•

Amount of barite on location.

•

Size of kick.

•

Time required to circulate out invading fluid.

•

Possible lost circulation zones.

•

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.

•

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.,