HYDRIL COMPANY LP / P.O. BOX / HOUSTON TEXAS PHONE: (281) / FAX: (281) / WEB:

Transcription

1

2 Please contact Hydril Pressure Control Equipment for any assistance or questions concerning the information in this manual. All information in this manual is the exclusive property of Hydril Company LP. PRESSURE CONTROL EQUIPMENT R HYDRIL COMPANY LP / P.O. BOX / HOUSTON TEXAS PHONE: (281) / FAX: (281) / WEB: HYDRIL COMPANY LP PRINTED IN U.S.A. MAY 2001 REV. B, JANUARY 2002

3 TABLE OF CONTENTS OPERATOR QUICK REFERENCE SECTION 1.0 INSTALLATION AND OPERATION 1.1 Surface Operation Subsea Operation SECTION 2.0 PHYSICAL DATA 2.1 Engineering Data Bolt and Wrench Data Outside Dimensions Inside Dimensions API Ring Joint Flange Data Clamp Hub Data SECTION 3.0 PACKERS AND SEALS 3.1 Packing Units Seals SECTION 4.0 MAINTENANCE AND TESTING 4.1 Maintenance Seal Testing Packing Unit Testing BOP Modifications SECTION 5.0 DISASSEMBLY AND ASSEMBLY 5.1 Disassembly Screwed Head Assembly Screwed Head Disassembly Latched Head Assembly Latched Head SECTION 6.0 PARTS AND STORAGE 6.1 Parts List Screwed Head Parts List Latched Head Preventor Storage Rubber Goods Storage PAGE 2

4 R CLOSING PRESSURE OPENING PRESSURE Control Pressures Surface Control Pressure psi Initial* WELL PRESSURE psi Pipe Size Closure / /2"-7" /8" /8"-16" * * * Close cautiously to prevent collapse of casing. CSO *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 graphs. 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. Subsea Operation Drilling Fluid Density Closing Pressure Increase Per 100 Foot Water Depth 10 lb./gal. 3 psi 12 lb./gal. 7 psi 14 lb./gal. 11 psi 16 lb./gal. 15 psi 18 lb./gal. 19 psi 3

5 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 MSP 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 pressure 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 3 Bore *21 1/4 in mm Closing Chamber Volume gal. (U.S.) liters Tape Measure 2 5/16" Rod Opening Chamber Volume gal. (U.S.) liters Recommended Test Pipe Size 4 1/2 in mm 1 Full Piston Stroke 11 1/4 in. 286 mm Distance From Top of Head To Top of Piston Screwed Head Maximum Piston Full Down 15 1/2 in. 394 mm Minimum Piston at Full Stroke 4 1/4 in. 108 mm Latched Head Maximum Piston Full Down 15 1/2 in. 394 mm Minimum Piston at Full Stroke 4 1/4 in. 108 mm *BOPs with 3000 psi top and bottom connectors have 20 3/4" bore. 4 Pressure Control Equipment R Sales Headquarters / P.O. Box / Houston, Texas Telephone: (281) / FAX: (281) Eastern Hemisphere / Hydril U.K. Ltd. Minto Avenue Altens Industrial Estate Aberdeen, AB1 4JZ Scotland / Telephone: / FAX:

6 PISTON INDICATOR WEAR PLATE PACKING UNIT HEAD OPENING CHAMBER PISTON BODY CLOSING CHAMBER Figure 1-1 Cutaway view of MSP with packing unit fully open 5

7 The Hydril MSPblowout 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. *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 Figure 1-2 Upward force exerted by the piston squeezes packing unit rubber inward into a sealing engagement. 6

8 Figure 1-3. Cutaway view of MSP 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. Cutaway view of MSP 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. Figure 1-5. Cutaway view of MSPBOP with packing unit closed on square kelly. The packing unit seals off on square or hexagonal kellys to rated pressure. Figure 1-6. Cutaway view of MSP 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. 7

9 1.1.1 Surface Hookup The surface hookup of the msp 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 MSP 21 1/4"-2000 BOP. During normal drilling operations, it is recommended that the pressure regulator valve for the msp be set at the initial closing pressure shown for the size pipe being used. This 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 OPENING PRESSURE Figure CSO CLOSING PRESSURE-PSI /2" PIPE 4 1/2"-7" PIPE 9 5/8" PIPE *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 70 o F. *13 3/8"-16" PIPE WELL / TEST PRESSURE-PSI 8 Figure 1-8: Average Control Pressure - MSP 21 1/4-2000

10 1.1.2 Surface Stripping Operations Drill pipe can be rotated and tool joints stripped through a closed MSP 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. 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, 4 1/2" drill pipe Precharge = 0.50 (Closing Pressure). From Figure 1-8: Closing Pressure = 670 psi Precharge = 0.50 x 670 psi Precharge = 335 psi 9

11 1.2.1 Subsea Operations Subsea Hookup When operating the MSP subsea, an adjustment pressure ( P) must be added to the closing pressure. The adjustment pressure ( P) compensates for the hydrostatic pressure of the drilling fluid column in the marine riser, which exerts an opening force on the BOP P for the GK 13 5/ subsea hookup is calculated from the following formula: Adjustment Pressure ( P) = (0.052 x Wm x Dw) (0.45 x Dw) p Where: Wm = drilling fluid density in lb./gal. Dw = water depth in feet = conversion factor p = 2.56 = the ratio of closing chamber area to the difference between the closing chamber and the opening chamber areas for the MSP 21 1/4" psi/ft. = pressure gradient for seawater using a specific gravity of seawater = 1.04 and psi/ft. pressure gradient for fresh water. The optimum closing pressure for subsea operation is obtained using the following formula: Subsea Closing Pressure = Surface Closing Pressure + Adjustment Pressure ( P). This can be done by one of two different methods: EXAMPLE: Method 1 4 1/2" pipe, initial closure, 16 lb./gal. drilling fluid, 500 ft. water depth. Subsea Closing Pressure = Surface Closing Pressure + Adjustment Pressure ( P). From the Control Pressure Graph, Figure 1-8: Initial Closing Pressure = 900 psi. Adjustment Pressure ( P) _(0.052 x 16 lb/gal. x 500 ft.) (0.45 psi/ft. x 500 ft.)_ 2.56 Adjustment Pressure ( P) = 74.6 psi Initial Subsea Closing Pressure = 900 psi psi = 975 psi. Proportionally reduce the closing pressure as well pressure increases, as shown in Figure 1-8. Method 1. Calculate the adjustment pressure ( P) and add it to the surface closing pressure found in the Surface Control Pressure Graph, Figure 1-8. OR Method 2. Find the adjustment pressure ( P) in the Adjustment Pressure Graph, Figure 1-10, and add it to the closing pressure found in the Control Pressure Graph, Figure 1-8. Closing Pressure Opening Pressure Figure

12 EXAMPLE: Method 2 4 1/2" pipe, initial closure, 16 lb./gal. drilling fluid, 500 ft. water depth. Subsea Closing Pressure = Surface Closing Pressure + Adjustment Pressure ( P). From Figure 1-8: Initial Closing Pressure = 900 psi. From Figure 1-10: Adjustment Pressure ( P) = 74.6 psi. Subsea Closing Pressure = 900 psi psi = 690 psi CSO CLOSING PRESSURE-PSI /2" PIPE 4 1/2"-7" PIPE 9 5/8" PIPE *Check specifications for collapse pressure of casing. *13 3/8"-16" PIPE Figure 1-8: Average Control Pressure - MSP 21 1/ WELL / TEST PRESSURE-PSI ADJUSTMENT PRESSURE ( P) PSI lb./gal. 16 lb./gal. 14 lb./gal. 12 lb./gal. 10 lb./gal WATER DEPTH - FEET Figure 1-10: Adjustment Pressure ( P) MSP 21 1/4"-2000 Subsea Hookup

13 1.2.2 Subsea Stripping Operations Drill pipe can be rotated and tool joints stripped through a closed subsea MSP packing unit, while maintaining a seal off on the pipe. Longest packing unit life is obtained by adjusting the closing forces low enough to maintain a seal with a slight amount of drilling fluid leakage around the drill pipe. The drilling fluid leakage indicates the optimum seal off for minimum packing unit wear and provides lubrication for the drill pipe motion through the packing unit. The pressure regulator valve should be set to maintain the proper control pressure. In subsea installations, a surge absorber (accumulator) of approximately 10-gallon size should be connected to the closing chamber. This surge absorber prevents pressure surges when stripping tool joints through a closed packing unit. Slow tool joint stripping speeds reduce surge pressures, thus prolonging packing unit life. The closing chamber surge absorber should be precharged to the hydrostatic pressure of the control fluid column plus 100 psi. An opening chamber surge absorber may be applied when the blowout preventer control system does not permit free bidirectional control fluid flow from and to the opening chamber during stripping operations. Precharge to 80% of the sea bottom water pressure (normally 0.45 psi/ft.). 12

14 Closing Chamber Surge Absorber Precharge Subsea Hookup Closing Pressure Opening Pressure The precharge pressure for the closing chamber surge absorber can be calculated using the following example or taken directly from Figure EXAMPLE: 4 1/2"-5 1/2" pipe, 500 ft. water depth. Precharge:.41 (Dw) psi Where: Dw = water depth in feet 0.41 psi/ft. = pressure gradient for control fluid (water and water soluble oil) using a specific gravity of the mixture = 0.95 and psi/ ft. pressure gradient for fresh water. Precharge = (0.41 psi/ft. x 500 ft.) psi. Precharge = 305 psi WATER DEPTH FEET PRECHARGE PRESSURE PSI Figure 1-11: Closing Chamber Surge Absorber Precharge Pressure MSP 21 1/4"-2000 Subsea Hookup 13

15 2.1 Engineering Data English Metric Bore **21 1/4 inches mm Working Pressure psi 138 BAR Shell Test Pressure (Factory Test Only) psi 207 BAR Closing Chamber Test Pressure (Factory Test Only) psi 207 BAR Opening Chamber Test Pressure (Factory Test Only) psi 207 BAR Volume Closing Chamber gallons liters Volume Opening Chamber gallons 71.5 liters Piston Stroke /4 inches 286 mm Port Size NPT*... Weight-Single (Approximate varies with connectors ,100 lb 6849 kg * 1 1/4" or 1 1/2" NPT available on request. ** BOPs with 3000 psi top and bottom connections have 20 3/4" bore. 2.2 Bolt and Wrench Data Ref. Description Thread Wrench Recommended Torque No. Size Lb/Ft Kg-m 2 Pipe Plug Piston Indicator 1/2" NPT 3/8" Hex Key Head Lock Screw 3/4"-10UNC 1 1/8" Hex Capscrew, Outer Body Sleeve 1"-8UNC 1" 12pt Socket Wear Plate Cap Screw 1/2-13UNC 1/2" -12pt. Socket Capscrew, Inner Body Sleeve 3/4"-10UNC 3/4" 12pt Socket Eyebolt, Piston 3/4"-10NC... Snug Snug... Eyebolt, Head 1 1/4"-7NC... Snug Snug... Screw, Protector Plate 1/2"-13UNC 3/4" Hex Snug Snug LATCHED HEAD ONLY 16 Head Clamp Screw 7/8"-9UNC 3/4" Hex Key Jaw Operating Screw 2 1/4"-8UN 2 1/2" Hex Jaw Holding Cap Screw 1/2"-14 NPT 3/4" Hex Key

16 2.3 Outside Dimensions Screwed Head Nominal Dimensions Inches with 2000 psi Bottom Connections A B C D E F G H J K L M N O P 52 1/2 Hub /2 23 1/8 Hub /2 6 3/ /8 45 1/4 51 3/4 58 3/4 52 3/ / Hub Hub 50 1/2 5 1/2 Nominal Dimensions Inches with 3000 psi Bottom Connections A B C D E F G H J K L M N O P 541/2 Hub /2 23 1/8 Hub /4 6 3/ /8 45 1/4 51 3/4 58 3/4 52 3/ /4 50 1/2 6 15

17 2.3 Outside Dimensions Latched Head Nominal Dimensions Inches with 2000 psi Bottom Connections A B C D E F G H J K L M N O 52 1/ /8 10 3/8 8 5/ / /4 56 5/ /2 1 3/4 45 1/4 51 3/4 Nominal Dimensions Inches with 3000 psi Bottom Connections A B C D E F G H J K L M N O /8 10 3/8 8 5/ / /4 56 5/ /4 45 1/4 51 3/4

18 2.4 Inside Dimensions Screwed Head NOMINAL DIMENSION A B C D E F *Bore O.D. Upper Piston I.D. Body I.D. Piston I.D. Piston Sealing Surface Piston Height INCHES 21 1/ /2 24 7/ /4 NOMINAL DIMENSION G H J K L M Ø Top of Sleeve to Bottom of Head Packing Unit Height Stroke Top of Head to Top of Piston (Full Down) Head Height Top of Head to Bottom of Wear Plate Piston Taper INCHES 11 15/ /4 11 1/4 15 1/2 * BOPs with 3000 psi top and/or bottom connections have 20 3/4" bore. 19 1/4 9 7/8 25 o 17

19 2.4 Inside Dimensions Latched Head NOMINAL DIMENSION A B C D E F *Bore O.D. Upper Piston I.D. Body I.D. Piston I.D. Piston Sealing Surface Piston Height INCHES 21 1/ /2 24 7/ /4 NOMINAL DIMENSION G H J K L M Ø Top of Sleeve to Bottom of Head Packing Unit Height Stroke Top of Head to Top of Piston (Full Down) Head Height Top of Head to Bottom of Wear Plate Piston Taper 18 INCHES 11 15/ /4 11 1/4 15 1/2 * BOPs with 3000 psi top and/or bottom connections have 20 3/4" bore. 19 1/4 9 7/8 25 o

20 2.5 API Ring Joint Flange Connections C C A Bolted Flange, Using Stud Bolts Studded Flange, Using Studs B FLANGE SEAL RING BOLTS & STUDS a Nominal Size (Inches) Bore Dia. (Inches) Max. API Service Pressure Rating (PSI) O.D. (Inches) Thickness (Inches) Dia. C (Inches) API Ring No. Req. Size Length b (Inches) Stud Bolts Studs B Bolt Circle Dia / /8 23 RX /8"-8UN 12 1/2 8 1/4 28 1/ / /4 4 3/4 23 RX "-8UN 15 1/ /2 Bolt Diameter, Inches POINT HEIGHT OF STUD BOLTS 1/2 to 7/ /8 Over 7/8 to 1 1/ /16 Over 1 1/8 to 1 5/ /4 Over 1 5/8 to 1 7/ /16 Over 1 7/8 to 2 1/ /8 Max. Point Height Inches a Bolt material shall be of a quality and strength not less than specified by ASTM A-320, Grade L7. 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. 2.6 Clamp Hub Connections J A C A G G B E F B E F Swing Bolted (with BX Gasket Hubs) H H Swing Bolted (with RX Gasket Hubs) HUB CLAMP Hub Size (Inches) Bore Size A (Inches) Rated Working Pressure Hub Dimensions (Inches) RX Only Seal Ring No. Standoff RX BX B C D J Clamp Dimensions (Inches) E F G H / /8 4 1/8 19/ /8 38 3/4 7 1/8 9 1/2 18 NO / /8 3 3/4 19/ /8 6 13/16 9 1/4 17 Clamp dimensions may vary from those shown. 19

21 3.1 Packing Units The heart of the MSP 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 resistant to tears and abrasion. All annular blowout preventer packing units are subjected to wear during closure and stripping. The design of the Hydril MSP 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. 20

22 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 30 o F ( 35 o C). 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 oil-base or oil-additive drilling fluids. It provides the best service with oil-base muds, when operated at temperatures below 20 o F ( 7 o C). 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 H 2 S Service does not affect selection of packing unit material. H 2 S 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 H 2 S 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. Figure 3-2 Natural Rubber Packing Unit No Band Figure 3-3 Synthetic Rubber Packing Unit Red Band No Band Red Band 21

23 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 (counter-clockwise). 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. 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 3-4 Figure 3-5 OPENING TORQUE Figure

24 3.1.2 Packing Unit Replacement Latched Head The latched head design of the MSP blowout preventer allows for easy replacement of the packing unit and eliminates loose parts that can be lost downhole or overboard. To replace the packing unit, use the following procedure: 1. Retract the jaw operating screws four turns to release the jaws from the head (see Figures 3-7 and 3-8). 2. Remove the head clamps and screws from top of head. 3. Lift out blowout preventer head. 4. Lift out old packing unit, lubricate the piston bowl, and.install the new packing unit. 5. Replace head and install head clamps and screws to pull head fully into place. 6. Tighten jaw operating screws four turns and torque to lb-ft. Figure 3-9 Head in place, but head clamps and screws have been removed, and jaw operating screws have been retracted (4 turns). Head Clamp Screw Head Clamp Head O-Ring Jaw Operating Screw Jaw Holding Capscrew Washer & Seal O-Ring Jaw Head Gasket Head Figure 3-7 Head latched in place and jaw operating screws tightened. Figure 3-10 Head clamps and head have been removed, but all latching mechanisms remain in body. Standoff Figure 3-8 Retract jaw operating screws 4 turns Figure 3-11 On assembly, if standoff between head and body occurs, use head clamps and screws to pull head fully into place. 23

25 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 90 o 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 3-13 Figure 3-12 Photo shows proper method for cutting through packing unit with a sharp knife. NOTE: The packing unit should be split only in the case of an emergency. The packing unit should be replaced as soon as possible with a unit that has not been split. 24

26 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. DYNAMIC SEALS STATIC SEALS DOUBLE U-SEAL cross-section with nonextrusion rings U-SEAL cross-section O-RING cross-section SQUARE RING cross-section 25

27 4.1 Maintenance Prior to placing the MSP blowout preventer into service, the following visual inspections (as noted in Figure 4-1) 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 or to the same size by installing inserts. NOTE: The Hydril MSP blowout preventer is a primary pressure vessel. When requested, the blowout preventer surfaces exposed to wellbore fluids will meet NACE Standard MR 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 Hydril authorized machine shop. 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 and outer body sleeves for wear, damage, and looseness. Check slots in sleeve for cuttings which may restrict piston movement. Older 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 Hydril approved 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 Figure 4-1

28 4.2 Seal Testing When it is known or suspected that a seal within the MSP 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 (lower), and 14. 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 (lower) or seal 14 is leaking. 2. Test seals 7(lower), 9 (upper), and 5. a. Pressurize opening chamber (1500 psi). b. Open closing chamber to atmosphere. IF: Fluid is seen coming from area between body and head seal 5 is leaking. IF: Fluid is seen coming into the wellbore seal 7 IF: (lower) is leaking. Fluid is seen at closing chamber seal 9 (upper) is leaking. 3. Test seals 7 (upper) and 10 (upper), and 14. a. Open closing chamber to atmosphere. b. Open opening chamber to atmosphere. c. Pressurize wellbore (2000 psi maximum). (Requires blind flange on top, as packing unit is open.) IF: Fluid is seen coming from the opening chamber seal 7 (upper) is leaking. IF: Fluid is seen coming from the closing chamber seal 10 (upper) or seal 14 is leaking. 4. For packing unit testing, see Section UPPER 7 LOWER 10 UPPER 10 LOWER 9 UPPER 9 LOWER 14 Figure

29 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 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 Packing Unit Testing Surface The MSP 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. 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. Use the minimum closing pressure that will establish and maintain a seal off. Piston Stroke can be measured on MSP 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 /16" Rod Distance From Top of Head Screwed Latched to Top of Piston Head Head Maximum (piston in full down position) 151/2" 15 1/2" Minimum (piston at full stroke) 4 1/4" 4 1/4" Packing Unit Testing-Subsea Prior to putting the MSP subsea, a surface packing unit test should be performed (see 4.3.1). When testing subsea, refer to Section 1.2 for Subsea Control Pressure. The closing pressure to effect initial seal off may vary with individual packing units. Begin the test with the recommended closing pressure and use the minimum closing pressure that will establish and maintain seal off. 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. 28

30 4.4 BOP Modifications Piston Indicator Hole Modification Older Model BOPs without piston indicator holes may be modified as shown in Figure 4-4 below. R = " PISTON INDICATOR BOP 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 the 20.25" radius from the centerline ( ) 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. 29

31 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 K. The Field Replacement Sleeve Kit contains the following: 1. 1 Drill Template /64" Dia. Pilot Drill /32" Dia. Counterbore Drill 4 1 1/2"-13NC Tap 5. 1 Bolted Body Sleeve /2"-13NC 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 20 o bevel that would interfere with the new sleeve (see Figure 4-5). 3. Insert drill template as shown in Figure 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"-13NC tap, 3/4" 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 1/8" 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"-13NC tap. 11.Install new sleeve and bolt down tight (see Figure 4-8). Grind All Weld From Counterbore And 20 o Bevel 27/64" Dia. Drill Drill Template Figure 4-5 Figure /32" Dia. Counterbore Drill With 27/64" Dia. Pilot 9 5/16 + 1/16" To Top Of Body Bolted Body Sleeve 30 Figure 4-7 9/16" Hole 19/32" Counterbore 1/2"-13NC Thread 27/64" Dia. Figure 4-8

32 5.1 Disassembly Screwed Head 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 (Item 8). 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 lock collar and capscrew (items 3 and 4). 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) 12 to 14 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 PACKING UNIT REMOVAL (ITEM 6) Install two (5/8"-11NC) eyebolts into packing unit. Lift packing unit out of piston. Use a sling of adequate length to prevent side loading of eyebolts PISTON REMOVAL (ITEM 8) Install two (3/4"-10NC) eyebolts in top of piston. 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! INNER BODY SLEEVE (ITEM 29) Remove the 16 inner body sleeve capscrews (Item 35) from around the sleeve. Lift out body sleeve by hooking sling through slots. Some model BOPs have a welded inner body sleeve which is not removable OUTER BODY SLEEVE REMOVAL (ITEM 12) Remove the 16 outer body sleeve capscrews (item 13) from around the body sleeve. Lift out body sleeve. Figure 5-1: Exploded View MSP 21 1/4"-2000 psi 31

33 Assembly Screwed Head CLEAN AND INSPECT ALL PARTS BEFORE ASSEMBLY Inspect all seals and replace any damaged seals or seals in use over one year. Install seal rings in positions shown by cross section! Coat all seal rings and seal ring grooves with silicon grease or castor oil prior to installation INNER BODY SLEEVE INSTALLATION (ITEM 29) Install slotted body sleeve (item 29) into inside bottom of blowout preventer body. Install 16 inner body sleeve capscrews (item 35) and torque to 120 lb-ft. Some model BOPs have a welded body sleeve which is not removable OUTER BODY SLEEVE INSTALLATION (ITEM 12) Lubricate and install O-ring (Item 14) on outer body sleeve. Lubricate and install inner U-seals (Item 10) in seal grooves at top of outer body sleeve. Lubricate mating surface of sleeve and body. Install sleeve in preventer body. Exercise caution to prevent pinching of the O-ring between the body and sleeve. Align sleeve with holes in the body and install 16 socket head cap screws (Item 13) and torque to 250 lb-ft PISTON INSTALLATION (ITEM 8) Lubricate and install lower U-seals (item 9) in seal grooves in piston. Lubricate and install middle U-seals (item 9) in seal grooves in middle segment of piston. Install two (3/4"-10NC) eyebolts in top of piston. Lubricate all mating surfaces and install piston into preventer body. Ensure that vertical alignment between piston and body is achieved prior to lowering piston. After alignment is achieved, the weight of the piston alone will take the piston its full normal stroke to the bottom of the preventer body. Remove eyebolts PACKING UNIT INSTALLATION (ITEM 6) Lubricate piston bowl. Lift packing unit with two (5/8"- 11NC) eyebolts and set into piston bowl HEAD INSTALLATION (ITEM 1) Lubricate and install upper U-seals (item 7) in seal grooves on inside of head. Lubricate and install head gasket (item 5) 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 antiseize compound. This lubrication will ensure easy removal at the next disassembly. Locate and mark hole in body for the lock collar and screw (items 3 and 4). 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 collar and cap screw (items 3 and 4). Remove eyebolts from head. Preventer is ready for use/ testing. Figure 5-2: Exploded View MSP 21 1/4"-2000 psi

34 Screwed Head BOP 33

35 5.1 Disassembly Latched Head 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 jaws (item 17) by rotating jaw operating screws (item 18) four turns counterclockwise until jaw shoulders against body. Excessive torque at shouldering should be avoided to prevent thread damage. Remove 4 head clamp screws (Item 16) and head clamps (Item 15). Install two (1 1/4"-7NC) eyebolts in top of head. Lift head slowly and assure a good vertical alignment PACKING UNIT REMOVAL (ITEM 6) Install two (5/8"-11NC) eyebolts into packing unit. Lift packing unit out of piston. Use a sling of adequate length to prevent side loading of eyebolts PISTON REMOVAL (ITEM 8) Install two (3/4"-10NC) eyebolts in top of piston. 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! INNER BODY SLEEVE REMOVAL (ITEM 29) Remove the 16 inner body sleeve bolts (item 35) from around the 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 OUTER BODY SLEEVE REMOVAL (ITEM 12) Remove the 16 outer body sleeve capscrews (item 13) from around the body sleeve (Item 12). Lift out body sleeve JAW & JAW OPERATING SCREW ASSEMBLY REMOVAL (ITEMS 17 through 22) Hold Jaw Operating Screw (item 18) and remove the Jaw Holding Capscrew (item 19). Remove the Jaw Operating Screw from the body. The Jaws (item 17) can now be removed from inside the blowout preventer body. Mark jaw sequence to assure same position on reassembly. If a new jaw is installed within a set of well worn jaws, the new jaw should be polished to match existing jaws thereby ensuring equal load sharing. 34 Figure 5-4: Exploded View MSP psi Latched Head BOP

36 5.2 Assembly Latched Head 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 and seal ring grooves prior to installation (Silicon grease or castor oil is best) INNER BODY SLEEVE INSTALLATION (ITEM 29) Install slotted body sleeve (item 29) into inside bottom of blowout preventer body. Install 16 inner body sleeve capscrews (item 35) and torque to 120 lb-ft. Some model BOPs have a welded body sleeve which is not removable OUTER BODY SLEEVE INSTALLATION (ITEM 12) Lubricate and install O-ring (Item 14) on outer body sleeve. Lubricate and install inner U-seals (Item 10) in seal grooves at top of outer body sleeve. Lubricate mating surface of sleeve and body. Install sleeve in preventer body. Exercise caution to prevent pinching of the O-ring between the body and sleeve. Align sleeve with holes in the body and install 16 socket head cap screws (Item 13) and torque to 250 lb-ft PISTON INSTALLATION (ITEM 8) Lubricate and install lower U-seals (item 9) in seal grooves in piston. Lubricate and install middle U-seals (item 9) in seal grooves in middle segment of piston. Install two (3/4"-10NC) eyebolts in top of piston. Lubricate all mating surfaces and install piston into preventer body. Ensure that vertical alignment between piston and body is achieved prior to lowering piston. After alignment is achieved, the weight of the piston alone will take the piston its full normal stroke to the bottom of the preventer body. Remove eyebolts PACKING UNIT INSTALLATION (ITEM 6) Lubricate piston bowl. Lift packing unit with two (5/8"-11NC) eyebolts and set into piston bowl JAW AND JAW OPERATING SCREW ASSEM- BLY INSTALLATION (ITEMS 17 THRU 22) Install jaws (Item 17) into cavity in body with square corner of teeth facing up and in the same sequence as disassembled. If a new jaw is installed within a set of well worn jaws, the new jaw should be polished to match existing jaws, thereby assuring equal load sharing. Install 0-ring (Item 22) in the external groove of the Jaw operating screw (item 18). Install jaw operating screw into body and screw in fully (hand tight). Do not over tighten causing jaw to extend beyond cavity in body. Install jaw holding capscrew seal (item 20) and nonextrusion ring (item 21) on the jaw holding capscrew (item 19). See drawing for placement and cross section. Install jaw holding capscrew into jaw operating screw and screw into jaw already installed in body cavity until tight (50 lb-ft.) Ensure all jaws are fully retracted into cavity by rotating jaw operating screw counterclockwise until jaws shoulder against body HEAD INSTALLATION (ITEM 1) Lubricate and install Head O-ring (Item 24) into groove on outside of blowout preventer head, just above the locking grooves. Lubricate and install upper U-seals (item 7) in seal grooves on inside of head. Lubricate and install head gasket (item 5) in seal grooves on outside of head, just below the locking grooves. Clean and lubricate locking groove on outside diameter oif head. Lift head (Item 1) and lower into body. Install head clamps (Item 15) and head clamp screws (Item 16) and pull head fully down until it shoulders against the BOP. Ensure that the head is fully shouldered against the body. Rotate the jaw operating screws clockwise to bottom jaws fully into the locking grooves in the head. Torque to about lb-ft. Remove eyebolts from head. Preventer is ready for use/testing. 35

37 NOTE: Seal Rings MUST BE installed in position shown by cross-section. Figure 5-5: Exploded View MSP psi Latched Head BOP 36

38 Latched Head BOP 37

39 6.1 Parts List Screwed Head Item No. Part Name Approx. No. Net Wt. Req. (Lb) Part Number Standard Assembly 1 15, Blowout Preventer Head 1 4, Pipe Plug, Piston Indicator Lock Collar Head Lock Screw Head Gasket Packing Unit- Natural Rubber (NR) Packing Unit- Nitrile Rubber (NBR) Packing Unit- Neoprene Rubber U-Seal, Upper Piston 1 2, U-Seal, Lower U-Seal, Inner Body 1 5, Body Sleeve, Outer Capscrew, Outer Body Sleeve O-Seal, Body Sleeve Body Sleeve, Inner *33 Wear Plate *34 Capscrew, Wear Plate Capscrew, Inner Body Sleeve Seal Set- Complete Field Replacement Sleeve Kit K ACCESSORIES... Chain Sling Assembly M... Eyebolt, Piston 1"-8 NC x 17" Lg M... Eyebolt, Head 1 1/4"-7 NC x 1 3/4" Lg Protector Plate Capscrew, Protector Plate Figure 6-1: Screwed Head MSP 21 1/4"-2000 psi 38 Recommended Spares for One Year Foreign Service. For converting welded sleeve on some model BOPs to bolted sleeve only. Sleeve does not interchangee with Item 4.

40 6.1 Parts List Latched Head Item No. Part Name BOP Assembly 1 16, BOP Head 1 4, Pipe Plug, Piston Indicator Head Gasket Packing Unit- Natural Rubber (NR) Nitrile Rubber (NBR) Neoprene Rubber U-Seal, Upper Piston 1 2, U-Seal, Lower U-Seal, Inner BOP Body 1 6, AA 12 Body Sleeve, Outer Capscrew, Outer Body Sleeve O-Seal, Body Sleeve Head Clamp Head Clamp Screw Jaws Jaw Operating Screw Capscrew, Jaw Holding Seal, Jaw Holding Screw Non-Extrusion Washer O-Ring, Jaw Operating Screw Relief Fitting Head O-Ring Body Sleeve, Inner *33 Wear Plate *34 Capscrew, Wear Plate Capscrew, Inner Body Sleeve Seal Set- Complete Field Replacement Sleeve Kit ACCESSORIES Approx. No. Net Wt. Req. (Lb) Part Number Order by BOP Serial Number... Chain Sling Assembly M... Eyebolt, Piston 1"-8 NC x 17" Lg M... Eyebolt, Head 1 1/4"-7 NC x 1 3/4" Lg Protector Plate C... Capscrew, Protector Plate Figure 6-2: Latched Head MSP 21 1/4"-2000 psi Recommended Spares for One Year Foreign Service. For converting welded sleeve on some model BOPs to bolted sleeve only. Sleeve does not interchangee with Item 4. 39