Gk11-5(6609B)

OPERATOR’S MANUAL

6609B (6671A)

DATA FOR INSTALLATION, OPERATION, MAINTENANCE & PARTS

Annular Blowout Preventer GK 11” Bore Size 5000 PSI

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OPERATOR'S MANUAL 6609B (6671A)

GK® 11"-5000 psi Annular Blowout Preventer

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Hydril Company LP/ P.O. Box 60458 / Houston, Texas 77205 Phone: (281) 449-2000 / FAX: (281) 985-2828 / WEB: www.hydril.com © 2001 HYDRIL COMPANY LP

PRINTED IN U.S.A.

REV B, JANUARY 2002

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OPERATOR’S MANUAL GK® 11”-5000 psi Annular Blowout Preventer

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GK® 11”-5000 psi Annular Blowout Preventer

Standard Hookup Closing Pressure Opening Pressure

Control Pressures ▲Surface Control Pressure —psi WELL PRESSURE—psi

Initial* Closure

500

1500

2500

3500

5000

2 3/8

900

825

650

475

300

50

2 7/8"

800

725

550

375

200

50

3 1/2"

825

450

275

100

50

50

4 1/2"-5 "

450

375

225

100

50

50

5 1/2"-8 5/8"

350

275

125

50

50

50

1150

1150

Pipe Size

Close cautiously to prevent collapse of casing. CSO

1150

1150

1150

1150

▲ *Use closing pressure shown at initial closure to establish seal off and reduce closing pressure proportionally as well pressure is increased. Well pressure will maintain closure after exceeding the required level. See Section 1 for control pressure graph. Closing pressures are average and will vary slightly with each packing unit. Optimum stripping is obtained by adjusting the Control Pressure to achieve a slight drilling fluid leakage as the tool joint passes through the packing unit.

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OPERATOR’S MANUAL

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ANNULAR BOP TESTING AND OPERATION Proper Procedure for pressure testing any annular blowout preventer (BOP) ensures subsequent seal off and maximum packing unit life. Reliable seal off tests are made by initially closing the packing unit with prescribed closing chamber pressure on the recommended size test pipe, proportionally reducing closing pressure as well pressure is increased, and by determining the remaining piston travel after seal off is achieved. Optimum packing unit life is obtained by testing at low rubber stress levels. Minimum packing unit stress is achieved by use of the minimum closing chamber pressure that will initiate and maintain seal off on the recommended size test pipe. The GK® blowout preventer is designed to be well pressure assisted in maintaining packing unit seal off once initial seal off has been effected. Initial seal off is effected by applying pressure to the closing chamber. As well pressure or test pressure is increased, the closing force on the packing unit also increases. As well pressure exceeds the required level the packing unit is maintained closed on the recommended size test pipe by well pressure alone. Once initial seal off is achieved, it is recommended that closing pressure be proportionally reduced as well pres-

sure is increased in order to maintain the optimum closing force on the packing unit. Optimum closing forces for high well pressures may require careful application of pressure to the opening chamber. Closing pressure required to effect initial seal off may vary slightly between individual packing units. Begin the test with the recommended initial closing pressure. Piston Stroke can be measured on GK® blowout preventers through a vertical passage in the top of the BOP head.* The maximum and minimum distances from the top of the head to the top of the piston are stamped on the BOP head and are also listed in the table below. Piston stroke remaining at seal off is a direct indicator of remaining packing unit life. Record the piston stroke and the closing pressure at seal off for each test. Compare with previous results and with maximum piston stroke for the BOP to ensure subsequent seal offs. A valid test on any annular BOP is only achieved when the remaining piston stroke is measured at test seal off.

*0lder model BOPs may not have vertical passage in head. See Section 4.3 for information on field modification.

OPERATIONAL DATA Bore

11 in.

279.4 mm

Closing Chamber Volume

9.81 gal. (U.S.)

37.1 liters

Opening Chamber Volume

8.08 gal. (U.S.)

30.6 liters

Recommended Test Pipe Size

3 1/2 in.

88.9 mm

Full Piston Stroke

7 1/8 in.

181 mm

TAPE MEASURE

5/16" ROD

Distance From Top of Head To Top of Piston Maximum — Piston Full Down

11 1/8 in.

283 mm

Minimum — Piston at Full Stroke

4 in.

102 mm

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Sales Headquarters / P.O. Box 60458 / Houston, Texas 77205 / Telephone: (281) 449-2000 FAX: (281) 985-2828 Eastern Hemisphere / Hydril U.K. Ltd. Minto Avenue Altens Industrial Estate Aberdeen, AB1 4JZ Scotland / Telephone: +441-224-878-824 / FAX: +441-224-898-524

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GK® 11”-5000 psi Annular Blowout Preventer

WEAR PLATE

PACKING UNIT

HEAD

OPENING CHAMBER

PISTON

CLOSING CHAMBER

Figure 1-1 Cutaway view of GK® with packing unit fully open.

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OPERATOR’S MANUAL

The Hydril® GK® blowout preventer is an annular blowout preventer which will close and seal off on drill pipe, tool joints, tubing, casing, or wireline in the wellbore or completely seal off the open hole to full rated working pressure by compression of a reinforced elastomer packing element. This preventer has been developed for use on surface installations and it can also be used subsea. In addition, the GK® meets the requirements of API Recommended Practices – R.P. 53*. Hydraulic pressure applied to the closing chamber (refer to Figures 1-2 through 1-6) raises the piston forcing the packing unit into a sealing engagement. Wellbore pressure (or test pressure) acting on the piston from below the sealed off packing unit further increases the closing force. Drill pipe can be rotated and tool joints stripped through a closed packing unit while maintaining a full seal on the pipe. Any normal closing unit having a separate pressure regulator valve for the annular blowout preventers and sufficient accumulator volume (see Section 2.1 of this manual for chamber volumes) can be used to operate the GK® blowout preventer. The hydraulic operating fluid may be clean, light petroleum hydraulic oil, or water with water soluble oil added. In cold climates, antifreeze should be added to prevent freezing. The closing time of the preventer is determined by the rate at which the hydraulic fluid can be delivered to the closing chamber. Minimum closing time is achieved by using short, large diameter control lines, large bore control valves, and a large accumulator volume. An excessively high setting on the pressure regulator valve will have little effect on BOP closing time.

Figure 1-2

*API Recommended Practices for Blowout Prevention Equipment Systems - R.P 53 is available from the American Petroleum Institute, Production Department, 1220 L Street, Northwest, Washington, DC 20005.

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Upward force exerted by the piston squeezes packing unit rubber inward into a sealing engagement.

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Figure 1-3. Cutaway view of GK® BOP with packing unit fully open. The Hydril® GK® opens to full bore to allow passage of large-diameter tools through open bore as well as maximum annulus flow of drilling fluids. Packing unit always returns to the open position due to normal resiliency of rubber packing unit. Retention of opening chamber pressure will provide positive control of piston and reduce wear caused by vibration.

Figure 1-4.

Figure 1-5.

Figure 1-6.

Cutaway view of GK® BOP with packing unit closed on square kelly. The packing unit seals off on square or hexagonal kellys to rated pressure.

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Cutaway view of GK® BOP with packing unit closed on drill pipe. The packing unit seals off on tool joints, drill pipe, casing, tubing, or wireline to rated pressure.

Cutaway view of GK® BOP with packing unit closed on open hole. Complete closure of packing unit safely holds well pressure, without leakage, equal to the rated working pressure of the preventer.

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1.1 Surface Operation 1.1.1 Surface Hookup The surface hookup of the GK® shown in Figure 1-7 connects the hydraulic control lines to the opening and closing chambers of the BOP Pressure applied to the closing chamber raises the piston and effects the initial seal between the packing unit and drill pipe. Well pressure or test pressure also acts on the piston below the sealed off packing unit and further increases the closing force acting on the packing unit. As the well pressure or test pressure exceeds the required level the preventer is maintained closed by well pressure alone. As well pressure further increases, the closing force on the packing unit also increases. Closing pressure should be proportionally reduced as well pressure is increased in order to maintain optimum closing force on the packing unit and prolong packing unit life. The Control Pressure Graph, Figure 1-8, shows the relationship of closing pressure and well pressure required to effect optimum seal off for the GK® 11”-5000 BOP. During normal drilling operations, it is recommended that the pressure regulator valve for the GK® be set at the initial closing pressure shown for the size pipe being used. This

Opening Pressure

Figure 1-7 pressure will ensure that initial seal off is achieved should a “kick” be encountered. During BOP testing operations, once initial seal off is achieved, closing pressure should be proportionally reduced as well pressure is increased.

▲ CLOSING PRESSURE-PSI

1500

CSO

1000 *Closing pressures are average and will vary slightly with each packing unit. Use closing pressure shown at initial closure to establish seal off and reduce closing pressure proportionally as well pressure is increased. Well pressure will maintain closure after exceeding the required level. **Close cautiously to prevent collapse of casing. Operating pressure may vary at temperatures other than 70oF.

500

23

/8"

2 7/

**5 1

/2" th

ru 8

4 1/ 2" th ru 5 "

5/8"

PIPE

3 1/

2" P

PIP E

PIP

E

8" P

IPE

IPE

0 0

1000

2000

3000

WELL PRESSURE-PSI

Figure 1-8:

Average Control Pressure –GK 11"-5000

4000

5000

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OPERATOR’S MANUAL

1.1.2 Surface Stripping Operations Drill pipe can be rotated and tool joints stripped through a closed GK® packing unit while maintaining a full seal off on the pipe. Longest life for the packing unit is obtained by adjusting the closing forces low enough to maintain a seal on the drill pipe with a slight amount of drilling fluid leakage as the tool joint passes through the packing unit. This drilling fluid leakage indicates optimum seal off for minimum packing unit wear and provides lubrication for the drill pipe motion through the packing unit.

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Slow tool joint stripping speeds reduce surge pressures, and thus prolong packing unit life. The pressure regulator valve should be set to provide and maintain the proper control pressure. If the pressure regulator valve does not respond fast enough for effective BOP control, a surge absorber (accumulator) should be installed in the closing chamber control line adjacent to the blowout preventer. Precharge the accumulator to one-half of the closing pressure required to effect a seal off at the existing well pressure for the pipe size in use.

Surface Hookup

Closing Pressure

Closing Pressure

Opening Pressure

Opening Pressure

Example Precharge Calculation: 500 psi well pressure, 3 1/2" drill pipe Precharge = 0.50 (Closing Pressure). From Figure 1-8: Closing Pressure = 450 psi Precharge = 0.50 x 450 psi Precharge = 225 psi

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2.1 Engineering Data English

Metric

Bore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 inches Working Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5000 psi

279.4 mm 351.55 kg/cm2

Shell Test Pressure (Factory Test Only) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,000 psi Closing Chamber Test Pressure (Factory Test Only) . . . . . . . . . . . . . . . . . . . . . . . . 5000 psi

703.1 kg/cm2 351.5 kg/cm2

Opening Chamber Test Pressure (Factory Test Only) . . . . . . . . . . . . . . . . . . . . . . 5000 psi Volume—Closing Chamber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.81 gallons

351.5 kg/cm2 37.1 liters

Volume—Opening Chamber . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.08 gallons Piston Stroke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1/8 inches

30.6 liters 181.0 mm

Port Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 NPT* Weight-Single (Approximate—varies with connectors . . . . . . . . . . . . . . . . . . . . . . . 8,200 lb

3720 kg

* 1 1/4" or 1 1/2" NPT available on request

2.2 Bolt and Wrench Data Ref. No.

Description

Thread

Wrench Size

17

Pipe Plug—Piston Indicator

1/2" NPT

3/8" Hex Key

18

Slotted Body Sleeve Bolt

1/2"-13UNC

3/4" Hex

19

Head Lock Screw

1"-8UNC

30

Wear Plate Cap Screw

...

Recommended Torque Lb/Ft Kg-m 50

6.9

55-75

7.6-10.4

1 1/4" Hex

100

13.8

1/2-13UNC

1/2" -12pt. Socket

70

9.6

Eyebolt, Piston x 17" Lg.

5/8"-11NC

....

Snug

Snug

...

Eyebolt, Head x 1 3/4" Lg.

1 1/4"-7NC

....

Snug

Snug

...

Protector Plate Screw

1/2"-13UNC

3/4" Hex

Snug

Snug

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GK® 11”-5000 psi Annular Blowout Preventer

2.3 Outside Dimensions

H AS CAST J K

E F

A AS CAST

C STUDDED

G

B CLAMP HUB

D AS CAST

*OPENING PORT

*CLOSING PORT M AS CAST

N AS CAST O AS CAST * 1" NPT, 1 set of ports, 45o from lifting lug unless otherwise specified. NOTE: Lifting lugs split lower connection stud holes and are equally spaced 90o apart. Lifting lugs are 1-1/4" thick with 1-1/2" diameter holes.

Nominal Dimensions — Inches A

B

C

D

E

F

19 1/16

5 11/16

13 3/16

▲5M

▲10M

▲5M

▲10M

▲5M

▲10M

47 3/4

48 1/2

44 7/8

51 1/2

39 5/8

40 1/4

G

H

J

K

L

M

N

O

11 13/16

44 1/4

37 1/2

35 3/4

...

2

32

36 3/4

▲ Lower Connector Pressure Rating

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GK® 11”-5000 psi Annular Blowout Preventer

2.4 Inside Dimensions

A

K

L M

G

H B C

Ø

J

D F

NOMINAL DIMENSION

E

A

B

C

Bore

O.D. Upper Piston

INCHES

11

NOMINAL DIMENSION

H

INCHES

D

E

I.D. Upper Body

24 1/4 J

Packing Unit Height

Stroke

12

7 1/8

F

G

I.D. Piston

I.D. Lower Body

Piston Height

Top of Sleeve To Bottom of Head

30 3/4

13 3/4

23 1/4

23 1/4

12 3/16

K

L

Top of Head to Top of Piston (Full Down) 11 1/8

M

Ø

Head Height

Top of Head to Bottom of Wear Plate

Piston Taper

14 7/16

6 5/8

20o

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GK® 11”-5000 psi Annular Blowout Preventer

2.5 API Ring Joint Flange Connections

C

C

B A

Studded Flange, Using Studs.

Bolted Flange, Using Stud Bolts.

FLANGE Nominal Size (Inches)

Bore Dia. (Inches)

Max. API Service Pressure Rating (PSI)

11

11

5000

11

11

10,000

SEAL RING O.D. (Inches)

Thickness (Inches)

† Dia. C (Inches)

API Ring

23

4 11/16

12 3/4

RX54

25 3/4

5 9/16

14.064

BX158

BOLTS & STUDSa No. Req.

Lengthb (Inches)

Size

Stud Bolts A

Studs B

Bolt Circle Dia. (Inches)

12

1 7/8

14 1/2

10 1/4

19

16

1 3/4

15 3/4

10 1/4

22 1/4

POINT HEIGHT OF STUD BOLTS Bolt Diameter, Inches

Max. Point Height Inches

1/2 to 7/8 . . . . . . . . . . . . . . . . . . . . . . Over 7/8 to 1 1/8 . . . . . . . . . . . . . . . . Over 1 1/8 to 1 5/8 . . . . . . . . . . . . . . Over 1 5/8 to 1 7/8 . . . . . . . . . . . . . . Over 1 7/8 to 2 1/2 . . . . . . . . . . . . . .

1/8 3/16 1/4 5/16 3/8

a

Bolt material shall be of a quality and strength not less than specified by ASTM A-193, Grade B7. Nuts shall be of a quality not less than ASTM A-194, Grade 2H. Stud bolts are threaded full length.

b

Lengths shown herein are overall lengths, including point at both ends, as shown in table. Dimensions shown are outside diameters of 6BX flange grooves.

†

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GK® 11”-5000 psi Annular Blowout Preventer

2.6 Clamp Hub Connections

J

A

C

A

G

G

B

B

E

E

F

F

H

H

HUB Bore Size A (Inches)

Rated Working Pressure (PSI)

11

11

11

11

Hub Size (Inches)

Seal Ring No.

Hub Dimensions (Inches) RX Only Standoff D C

RX

BX

B

5000

53

...

16 1/4

3 3/4

15/32

...

10,000

...

158

16 1/4

...

...

3 5/8

NOTE: API 16A 1st Edition Nov 1, 1986 Does Not Include Clamps.

Clamp Dimensions (Inches) ▲

E

F

G

H

20 13/16

28 1/2

6 3/4

...

20 13/16

28 1/2

6 3/4

...

▲ Clamp dimensions may vary from those shown.

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GK® 11”-5000 psi Annular Blowout Preventer

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3.1 Packing Units The heart of the GK® blowout preventer is the packing unit. The unit is manufactured by Hydril from high quality rubber, reinforced with flanged steel segments. Each unit has a large volume of tough, feedable rubber to meet any requirement. The molded-in steel segments have flanges at the top and bottom These segments anchor the packing unit within the blowout preventer and control rubber extrusion and flow when sealing off well pressures. Since the rubber is confined and kept under compression, it is

Figure 3-1 Cutaway drawing showing how rubber is molded around steel segments.

resistant to tears and abrasion. All annular blowout preventer packing units are subjected to wear during closure and stripping. The design of the Hydril® GK® blowout preventer causes closure wear to occur on the outside of the packing unit while stripping wear occurs on the inside. Because the packing unit uses the principle of feeding rubber from the back of the packing unit to the bore, stripping life may be affected by a packing unit that is worn on the backside.

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GK® 11”-5000 psi Annular Blowout Preventer

3.1.1 Packing Unit Selection Because of the importance of the packing unit to the operation of the blowout preventer and to the safety of the crew and rig, only genuine Hydril® packing units should be used as replacements for original equipment. All Hydril® packing units are tested to full rated pressure inside a test blowout preventer at the factory as part of standard performance tests before being furnished to the consumer. Packing units for Hydril® blowout preventers are manufactured from compounded natural rubber or nitrile rubber. Natural Rubber is compounded for drilling with waterbase drilling fluids. Natural rubber can be used at operating temperatures down to –30oF (–35oC). When properly applied, the compounded natural rubber packing unit will usually provide the longest service life. This all-black packing unit is identified by a serial number with the suffix "R" or "NR." Nitrile Rubber (a synthetic compound) is for use with oilbase or oil-additive drilling fluids. It provides the best service with oil-base muds, when operated at temperatures below 20oF (–7oC). The nitrile rubber packing unit is identified by a red colored band and a serial number with the suffix "S" or "NBR." Seals for Hydril® blowout preventers are manufactured from a special nitrile rubber material which provides long, trouble-free service in sealing against oil gas, or water. Expected H2S Service does not affect selection of packing unit material. H2S service will reduce the service life of rubber products, but the best overall service life is obtained by matching the packing unit material with the requirements of the specific drilling fluid. Performance of elastomeric materials can vary significantly, depending on the nature and extent of exposure to hydrogen sulfide. The operator should monitor pressure sealing integrity by frequently performing a packing unit seal test to assure no performance degradation has occurred. Hydril recommends replacement of all rubber goods after H2S exposure. Storage Conditions such as light, heat or adverse conditions are significant factors in the storage life of packing units, as covered in Section 6.3 and should be avoided.

No Band

Figure 3-2 Natural Rubber Packing Unit – No Band

Red Band

Figure 3-3 Synthetic Rubber Packing Unit – Red Band

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3.1.2 Packing Unit Replacement– Screwed Head To replace the packing unit, use the following procedure: 1. Remove head lock screw. 2. Unscrew blowout preventer head (counterclockwise). 3. Lift off blowout preventer head. 4. Lift out packing unit. 5. Lubricate piston bowl. 6. Install new packing unit. 7. Clean and lubricate head and body threads with zinc base API modified tool joint lubricant. 8. Replace head and tighten to align hole for lock screw. 9. Install head lock screw and torque to 100 lb-ft.

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OPENING TORQUE

Figure 3-5

NOTE: If the head was improperly installed at last reassembly, it may be necessary to apply considerably more torque on the head by the use of a catline or winch while alternately applying and releasing pressure to the opening chamber (1500 psi maximum). Do not attempt to loosen the head by applying heat. Refer to Assembly/Disassembly Section for further information.

Figure 3-6

Figure 3-7

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OPERATOR’S MANUAL

3.1.3 Splitting Packing Units Packing unit replacement is also possible with pipe in the hole. After removing worn packing unit, cut new packing unit completely and smoothly through one side between any two steel segments perferably 90o from eyebolt holes to achieve easier handling. Cut should be made with a sharp knife as this will not affect the efficiency of the packing unit. Spring segment apart with a pry bar to put rubber in tension for easier cutting. Do Not use a saw or other rough cutting tool. Spring packing unit open sufficiently to pass around pipe, drop unit into position in blowout preventer body, and replace head.

Figure 3-9

Figure 3-8 Photo shows proper method for cutting through packing unit with a sharp knife.

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3-5

3.2 Seals The seal rings for Hydril® blowout preventers are manufactured from a special synthetic rubber material for long trouble-free sealing service. To prevent seal damage, Do Not use synthetic fluids in the hydraulic operating system. The hydraulic operating fluid may be clean, light petroleum hydraulic oil, or water with soluble oil added. In cold climates, antifreeze should be added to prevent freezing.

The dynamic seals are all molded, lip-type, pressureenergized rings. The static seals are of O-ring or square ring configuration. For seal replacement procedure, see Section 5.2. For seal maintenance and testing, refer to Section 4.0.

DYNAMIC SEALS

STATIC SEALS

DOUBLE U-SEAL cross-section with nonextrusion rings

U-SEAL cross-section

O-RING cross-section

SQUARE RING cross-section

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4-1

4.1 Maintenance Prior to placing the GK® blowout preventer into service, the following visual inspections should be performed: 1. Inspect upper and lower connections for pitting, wear, and damage—especially in ring grooves and stud bolt holes. Worn or damaged ring grooves must be welded, machined, and stress relieved. Worn or damaged stud bolt holes can be drilled and tapped to the next larger size and fitted with step-studs. NOTE: The Hydril® GK® blowout preventer is a primary pressure vessel. The blowout preventer surfaces exposed to wellbore fluids will meet NACE Standard MR-01-75. Proper handling and repair are required to maintain any original integrity. Field welding is not recommended as it induces undesirable stresses which must be relieved by proper heat treating procedure or controlled by special welding procedures. 2. Check the body for wear and damage—especially in the internal cylinder walls for pits and vertical scores. Minor pits and scores can be removed in the field with emery cloth. Repaired surface should be coated with silicon grease or castor oil. Severe pits and scores may require machining and/or welding which should be performed in a machine shop. Cracks must be corrected. 3. Inspect the vertical bore for wear and damage from drill string and drill tools—especially in the area of the ring grooves. If wear is excessive, the area must be repaired. 4. Check the inner body sleeve for wear, damage, and looseness. Check slots in sleeve for cuttings which may restrict piston movement. Some model BOPs have a welded body sleeve and may be field repaired by conversion to a bolted sleeve (see Section 4.4).

5. Check for piston damage and wear—especially the inner and outer walls for pits and vertical scores and the tapered bowl for pits and gouges. Minor pits and scores on the walls can be removed in the field with emery cloth. Repaired surface should be coated with silicon grease or castor oil. Severe pits and scores may require machining and/or welding which should be performed in a machine shop. Pits and gouges in the tapered bowl should be filled with a permanent type adhesive, such as epoxy. Sharp or rolled edges should be removed with emery cloth or a grinder. Repair will be satisfactory when a relatively smooth surface is achieved. 6. Check the wear plate in the inner bottom face of the head for wear. In addition to the aging process of time and use, wear of this metal surface is produced by the combination of vertical (upward thrust) and lateral forces. These forces are generated each time the packing unit is closed. Severe wear is exhibited in the form of grooves or channels shaped by the steel segments of the packing unit. The inner bottom face of the head serves as a wall to prevent upward movement of the packing unit. Friction between these metal surfaces is controlled at a level which does not impair lateral movement of the packing unit. Repair of this surface is accomplished by replacing the wear plate. Some models of this BOP do not have the wear plate, but may be converted. 7. Inspect the packing unit for wear, cracking, hardness, and correct elastomer composition. See Section 3 for packing unit information and Section 4.3 for packing unit testing. 8. Check seal ring for nicks, cuts, fraying of lips, and abrasion. Worn or damaged seal rings should be replaced. See Section 4.2 for pressure testing of seals. 6

1

7

3

5 8

8

2

3

1

Figure 4-1

4

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4.2 Seal Testing When it is known or suspected that a seal within the GK blowout preventer is leaking, it is recommended that all seals be replaced. However, if only the seal in question is to be replaced, it must first be determined which seal is leaking. The following procedure is provided: 1. Test seals 9 (lower) and 10 (upper). a. Pressurize closing chamber. The test pressure to be used in the closing chamber should be the initial closing pressure required using the recommended test mandrel if a packing unit is installed (1500 psi if no packing unit is installed). b. Open opening chamber to atmosphere. IF: Closing fluid is seen at opening chamber—seal 9 (lower) is leaking. IF: Closing chamber pressure gauge is dropping and no fluid is seen at opening chamber—seal 10 (upper) is leaking. 2. Test seals 8 (lower), 9 (upper), and 6. a. Pressurize opening chamber (1500 psi). b. Open closing chamber to atmosphere. IF: Fluid is seen coming from area between body and head—seal 6 is leaking. IF: Fluid is seen coming into the wellbore—seal 8 (lower) is leaking. IF: Fluid is seen at closing chamber—seal 9 (upper) is leaking. 3. Test seals 8 (upper) and 10 (lower). a. Open closing chamber to atmosphere. b. Open opening chamber to atmosphere. c. Pressurize wellbore (5000 psi maximum). (Requires blind flange on top, as packing unit is open.) IF: Fluid is seen coming from the opening chamber— seal 8 (upper) is leaking. IF: Fluid is seen coming from the closing chamber— seal 10 (lower) is leaking. 4. For packing unit testing, see Section 4.3.

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8 UPPER

8 LOWER

9 UPPER 9 LOWER 10 UPPER 10 LOWER

Figure 4-2

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4.3 Packing Unit Testing Proper procedure for pressure testing any annular blowout preventer ensures subsequent seal off and maximum packing unit life. Reliable pressure seal off tests are made by closing the packing unit with prescribed closing chamber pressure on recommended size test pipe and by

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determining the remaining piston travel after seal off is achieved. Optimum packing unit life is obtained by testing at low rubber stress levels. Minimum packing unit stress is achieved by use of the minimum closing chamber pressure that will initiate and maintain a seal off on the recommended size test pipe.

4.3.1 Packing Unit Testing—Surface The GK® blowout preventer is designed to be well pressure assisted in maintaining packing unit seal off once initial seal off has been effected. Initial seal off is effected by applying pressure to the closing chamber. As well pressure or test pressure increases, the closing force on the packing unit also increases. As well pressure exceeds the required level, the packing unit is maintained closed on pipe by well pressure alone. During routine BOP testing, once initial seal off is achieved, closing pressure should be proportionally reduced as well pressure is increased (see the Control Pressure Graph, Figure 1-8). Closing pressure required to effect initial seal off may vary between packing units. Begin the test with the recommended initial closing pressure shown in Figure 1-8, depending on the style packing unit installed. Piston Stroke can be measured on GK® blowout preventers through a vertical passage in the top of the BOP head. The maximum and minimum distances from the top of the head to the top of the piston are stamped on the BOP head and are also listed in the table below. Piston stroke remaining at seal off is a direct indicator of remaining packing unit life. Record the piston stroke and the closing pressure at initial seal off for each test. Compare with previous results and with maximum piston stroke for the BOP to ensure subsequent seal offs. A valid test on any annular BOP is only achieved when the remaining piston stroke is measured at test seal off.

TAPE MEASURE

5/16" ROD

Distance From Top of Head to Top of Piston Maximum (piston in full down position) Minimum (piston at full stroke)

11-1/8" 4"

Figure 4-3: Piston Stroke Measurement Older model BOPs may not have the Piston Indicator Hole as shown in Figure 4-3 above. See Section 4.4 for modilcation.

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4.4 BOP Modifications 4.4.1 Piston Indicator Hole Modification Older Model BOPs without piston indicator holes may be modified as shown in Figure 4-4 below.

R – 11.968"

.719 DRILL 1/2"-14NPT TAP

CL PISTON INDICATOR

BOP CL

.339" DIA. DRILL THROUGH

Figure 4-4: Field modification for addition of Piston Indicator Hole to older model BOPs.

The procedure* for adding the piston indicator hole is as follows: 1. Drill one .339" diameter hole through the BOP head at a point located on R=11.968" radius from the centerline ( CL) of the BOP Head.

2. Counterbore with .719 " diameter drill. x 1 3/8" deep. 3. Tap the .719" diameter hole with a 1/2"-14 NPT tap. 4. Insert a 1/2"-14NPT pipe plug and torque to 50 lb-ft. * A drill press should be used.

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4.4.2. Bolted Body Sleeve Modification To maintain original integrity without welding, older model BOPs having a welded body sleeve may be repaired through conversion to a bolted sleeve. This conversion is accomplished by using the Field Replacement Sleeve Kit, part number 1006100. The Field Replacement Sleeve Kit contains the following: 1. 1—Drill Template 2. 1—27/64" Dia. Pilot Drill 3. 1—19/32" Dia. Counterbore Drill 4 1—1/2"-13UNC Tap 5. 1—Bolted Body Sleeve 6. 12—1/2"-13UNC X 1 1/4" Lg. Hex Head Cap Screws The procedure for converting the BOP from a slotted body sleeve to a bolted sleeve is as follows: 1. Remove old body sleeve. 2. Grind out all weld from the counterbore and the 20o Grind All Weld From o Counterbore And 20 Bevel

bevel that would interfere with the new sleeve (see Figure 4-5). 3. Insert drill template as shown in Figure 4-6. 4. Drill one 27/64" diameter hole, 1 1/4" deep, through one of the 27/64" diameter holes in the template. NOTE: Template has eleven 27/64" diameter holes and one 9/16" diameter hole. 5. Remove the template and counterbore hole with 19/32" diameter drill (see Figure 4-7). 6. Tap the hole with 1/2"-13UNC tap, 1" deep. 7. Re-insert the template and bolt to the BOP through the 9/16" hole in the template. 8. Drill a 27/64" diameter hole, 1 1/4" deep, in the 11 remaining places. 9. Remove the template and counterbore 19/32" diameter in 11 places. 10. Tap 11 holes with 1/2"-13UNC tap. 11. Install new sleeve and bolt down tight (see Figure 4-8). 27/64" Dia. Drill

Figure 4-5

Drill Template

Figure 4-6 13 1/8 +/– 1/16" To Top Of Body

19/32" Dia. Counterbore Drill With 27/64" Dia. Pilot Bolted Body Sleeve

Figure 4-7

9/16" Hole 19/32" Counterbore 1/2"-13UNC Thread 27/64" Dia.

Figure 4-8

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5.1 Disassembly 5.1.1 HEAD REMOVAL (ITEM 1) Close and open the packing unit to break loose any accumulation of drilling fluid or debris which may be restricting full downward travel of the piston. Vent opening and closing chambers to atmosphere ensuring that no trapped pressure exists which will cause personnel and/or equipment damage. Open valves in control system to have an exhaust and/or loosen hydraulic connections to allow leakage. Release head by removing the head lock screw (item 19). Install two (1 1/4"-7NC) eyebolts in the top of the head in the holes provided. Use a piece of strong pipe or rod (3" -4" pipe) 10 to 12 feet long as a lever against the eyebolts to apply counterclockwise torque (left hand) on the head. Rotate head (approximately 10 turns) to release, then lift clear of BOP. A vertical lift may be applied to the eyebolts to take the weight of the head off of the threads while applying torque to the head. This lift will reduce the required opening torque. If the head was improperly installed at the last reassembly, it may be necessary to apply considerably more torque on the head by the use of a winch or catline while alternately applying and releasing pressure to the opening chamber (1500 psi maximum). DO NOT attempt to loosen the head by applying heat on the thread area. 5.1.2 PACKING UNIT REMOVAL (ITEM 2) Install two (5/8"-11UNC) eyebolts into packing unit. Lift packing unit out of piston. Use a sling of adequate length to prevent side loading of eyebolts. 5.1.3 PISTON REMOVAL (ITEM 3) Install two (5/8"-11UNC) eyebolts in top of piston. Place a wooden spacer block (approximately 1/2" thick) between each eyebolt and the piston wall to protect the piston sealing surface. Gently lift piston vertically to free from preventer body. If a vertical lift is unfeasible or if the piston does not freely lift out, slowly apply low (50 psi) hydraulic pressure to the closing chamber-DO NOT USE AIR OR GAS! 5.1.4 SLOTTED BODY SLEEVE REMOVAL (ITEM 4) Remove the six slotted body sleeve bolts (item 18) from around the slotted body sleeve. Lift out slotted body sleeve with a sling and hooks under the slots. Some model BOPs have a welded body sleeve which is not removable.

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NOTE: Seal Rings MUST BE installed in position shown by cross-section. 17

19

1 6 8 29 30 2

1 3

9 10

4

18

5

Figure 5-1: Exploded View GK® 11"-5000 psi

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5.2 Assembly 5.2.1 CLEAN AND INSPECT ALL PARTS BEFORE ASSEMBLY Inspect all seals and replace any damaged seals or seals in use over one year. Seal rings MUST BE installed in positions shown by cross section! Lubricate all seal rings prior to installation. (Silicon grease or castor oil is best). 5.2.2 SLOTTED BODY SLEEVE INSTALLATION (ITEM 4) Install slotted body sleeve (item 4) into inside bottom of blowout preventer body. Install six slotted body sleeve bolts (item 13) and torque to 70-90 lb-ft. Some model BOPs have a welded body sleeve which is not removable. 5.2.3 PISTON INSTALLATION (ITEM 3) Lubricate and install lower U-seals (item 10) in seal grooves in lower segment of piston. Lubricate and install middle U-seals (item 9) in seal grooves in middle segment of piston. Install two (5/8"-11UNC) eyebolts in top of piston with wooden spacer blocks between eyebolt and piston wall. Lubricate all mating surfaces before lowering piston into body. Install piston into preventer body. Ensure that vertical alignment between piston and body is achieved prior to lowering piston. After proper alignment is obtained, the weight of the piston alone will take the piston its full normal stroke to the bottom of the preventer body. Be careful to prevent seal damage during assembly. Remove eyebolts and spacer blocks. 5.2.4 PACKING UNIT INSTALLATION (ITEM 2) Lubricate piston bowl. Lift packing unit with two (5/8"-11UNC) eyebolts and set into piston bowl, already installed in preventer. 5.2.5 HEAD INSTALLATION (ITEM 1) Lubricate and install upper U-seals (item 8) in seal grooves on inside of head. Lubricate and install head gasket (item 6) on outside of head just above screw threads. Clean threads of foreign matter and check threads for burrs or rough edges. Apply a generous coating of zinc base (lead-free) tool joint lubricant to the threads of head and body. This lubrication will ensure easy head removal at the next disassembly. Locate and mark hole in body for the head lock screw (item 19). Lift head using the two (1 1/4" -7NC) eyebolts and chain sling assembly. Align the lead thread of the head with the lead thread in the body. Screw head clockwise (right hand) into body until it shoulders against top of body. Line up lock screw hole in head with hole in body and install head lock screw (item 19). Remove eyebolts from head. Preventer is ready for use/ testing.

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NOTE: Seal Rings MUST BE installed in position shown by cross-section. 17

19

1 6 8 29

30 2

1 3

9 10

4

18

5

Figure 5-2: Exploded View GK® 11-5000 psi

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Pipe Plug (17)

Head Lock Screw (19) BOP Head – Screwed (1) Head Gasket (6) Wear Plate Capscrew (30) Wear Plate (29) U-Seal, Upper (8) Packing Unit (2) Piston (3) U-Seal, Middle (9) Body (5)

Slotted Body Sleeve (4)

U-Seal, Lower (10)

Slotted Body Sleeve Capscrew (18)

Figure 5-3: Cutaway of GK® 11-5000 BOP Showing Position of Parts

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6.1 Parts List — Screwed Head Item No.

Part Name

No. Req.

Approx. Net Wt. (Lb)

Part Number

17

BOP Assembly BOP Head -

1

8,200

1002140

Screwed Packing Unit-

1

1,880

1002143

6

Natural (NR) Packing Unit-

1

305

31401-R

8

Nitrile (NBR) Packing Unit-

1

311

31401-S

Neoprene Piston

1 1

311 1,380

4**

Slotted Body Sleeve

1

...

1004201

5 6

Body Head Gasket

1 1

4,645 2

1002141 31402

8 9 10

U-Seal , Upper U-Seal, Middle U-Seal, Lower

2 2 2

2.13 2 1.75

17

Pipe Plug, Piston Indicator

1

...

190006505

Slotted Body Sleeve Capscrew

12

...

192002612012

19 29*

Head Lock Screw Wear Plate

1 1

30*

Wear Plate Capscrew

•

Field Replacement Sleeve Kit ...

1 2▲

3

18**

▲

19

1

31401-N 1002145-1

30 2

1

31403 30736 32599

3

9 10

1002149 1004203

4

.13

192002608007

18

...

1006100

14.41

1002150

1

45

33565-M

2

1.94

30952

2

4.25

32006

Protector Plate Protector Plate

1

66

31406 1900043-

Figure 6-1:

Screw

4

.13

08010

Screwed Head GK® 11"-5000 psi

6

Seal Kit- Complete

1.19 24.15

29

ACCESSORIES ... ...

...

Chain Sling Assembly Eyebolt —Piston 5/8"-11 UNC x 10" Lg. Eyebolt, Head 1 1/4"-7 NC x 1 3/4" Lg.

... ...

▲ Recommended Spares for One Year Foreign Service.

•

5

For converting welded sleeve on some model BOPs to bolted sleeve only. Sleeve does not interchangee with Item 4.

* Requires head conversion to accept wear plate; some models of this BOP do not have the wear plate. ** Some BOPs are equipped with Sleeve P/N 1004075 and Capscrew 1920026-12016. Check P/N stamped on bottom of sleeve for replacement.

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6.3 Preventer Storage At the conclusion of each well, or prior to placing the blowout preventer in storage for even a brief period, it is recommended that the preventer be disassembled, cleaned, inspected, lubricated thoroughly with non-petroleum base oil such as castor oil, silicon oil, or rapeseed oil, and reassembled. Replacement of worn packing units, or packers, seal rings, and other parts can be made conveniently at this time. Flange or Hub faces and ring grooves should be protected with wooden covers and ports should be plugged.

6.4 Rubber Goods Storage The term rubber goods includes synthetic compounds such as Nitrile Copolymers and Neoprene, as well as natural rubber parts. The ideal storage situation for rubber goods would be in vacuum-sealed containers maintained in a cool, dry, dark storage area. Atmosphere, light, and heat accelerate deterioration of rubber goods. The term “aging” means cumulative effects of all three attacking agents over a period of time. The rubber goods are also affected by stretching or bending from normal shape, extreme cold, or chemical reactions with solvents and petroleum products. The following recommendations will allow vendors and users of oil field equipment to maximize normally available storage facilities for rubber goods. 1. Keep the rubber storage area as dark as possiblepreferably indoors, not outdoors, and away from direct sunlight, skylights, windows, and direct artificial lighting. The ultraviolet content of the light spectrum accelerates cracking. 2. Select a cool location (ideally below 90oF) that is away from heaters, stoves, and direct blasts of space heaters. Heat causes a gradual hardening of rubber goods. The process is greatly accelerated when ozone or oxygen is present. In extremely cold climates, some rubber goods become so brittle they will shatter when dropped or handled roughly. 3. Keep rubber goods away from electrical machinery (motors, switch gear, or any high voltage equipment producing corona). Avoid locations susceptible to drafts that will carry the atmosphere from electrical machinery to the rubber goods storage area. Exposure to the atmosphere allows oxygen and thus ozone (O3), a very active form of oxygen, to react with and be especially detrimental to rubber goods. Two principal sources of ozone are (1) atmospheric ozone, and (2) ozone created by electrical discharges such as lightning, high voltage corona, and electrical machinery.

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Points of strain in rubber goods attacked by ozone are characterized by deep cracks. Ozone and oxygen (O2) attack rubber goods much as steel rusts. Oxidation is characterized by a hard skin which eventually crazes in small cracks and may turn chalky or assume a barklike appearance. 4. The practice of first-in, first-out is essential with rubber goods. 5. Store rubber goods in a relaxed position in their normal shape; stretching or bending of rubber goods will result in accelerated aging or cracking. For example, do not hang 0rings on pegs, glands, BOP testers, or operator parts. Periodically inspect and treat with age resistant compounds the rubber goods that must be stored in a stretched attitude to detect aging signs. 6. Rubber goods storage areas should be kept as dry as possible. Remove oil, grease, or other foreign materials from the storage area to preclude spillage on rubber goods. Rubber goods, both natural and synthetic, possess some degree of susceptibility to deterioration from various solvents, especially oil field liquid hydrocarbons, which cause swelling/shrinkage. 7. If storage for extended periods is anticipated, sealed containers are recommended. Impervious surface coverings such as waxing will increase shelf life. Since the aging of a rubber product is dependent upon all of the above factors plus its size, specific composition, and function, no precise figure is available for “storage life.” Generally, the greater the ratio of surface area to volume, the more susceptible a part is to being rendered useless by aging. For example, a relatively large part (by volume), such as a packing unit, might be expected to have a much longer useful shelf life than a thin-walled, large-diameter 0ring. No general rule can be drawn regarding usability. A large, heavy part might suffer the same total amount of aging as a small, light piece and still be usable, whereas the light piece would be rendered useless. Thus, judgement becomes the rule and where there is doubt-replace the part. Prior to using rubber goods that have been stored for periods of time, these checks should be made: 1) Is there “chalking” or “barking”? 2) Has the part developed a “hard skin”? 3) Do cracks appear? (Sometimes cracks will be obvious; stretch or bend the part in question so that any incipient cracks or very thin cracks will be revealed.) 4) Will a suspect part pass a hardness test? (In the event that the hardness runs 15 points higher than the normal hardness of the part, it is considered nonusable.) Note: Hardness is affected by temperature, and readings should be taken with the rubber part at 70o to 100oF.

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HYDRIL COMPANY LP 3300 N. Sam Houston Pkwy. E. Houston, Texas 77032-3411 (281) 449-2000