GL 18-3/4” 5,000 psi Annular Blowout Preventer ® GL 18-3/4” 5,000 psi Annular Blowout Preventer

Definitions Blowout Preventer (BOP) Annular BOP The equipment (or valve) installed at the wellhead to contain wellbore pressure either in the annular space between the casing and the tubulars or in an open hole during drilling, completion, testing,or workover operations. Annular BOP A BOP that uses a shaped elastomeric sealing element to seal the space between the tubular and the wellbore or an open hole.

Hydril GL ABOP Latched head design for easy access Only two moving parts for simplicity Piston design to prevent piston binding Field replaceable wear plate Opening and closing chamber tested to BOP operating pressure - secondary chamber to twice BOP operating pressure API 16A monogram

Hydril GL ABOP Large lip-type seals for improved reliability All packing units are factory acceptance tested BOP acoustic emission monitored during shell test Materials are resistant to sulfide stress cracking - meet the requirements of NACE 3 models

Piston Operation Piston raised by applying closing pressure Packing unit squeezed inward to sealing engagement with pipe in the hole or with itself on open hole

Packing Unit - Fully Open Full bore opening to pass large diameter tools and allow maximum annulus flow Returns to full bore because of normal packing unit resiliency Retention of opening pressure reduces piston wear caused by vibration

Packing Unit - Closed on Pipe Closed on drill pipe Seals on tool joints, pipe, casing, tubing or wire line to rated working pressure

Packing Unit - Closed on Kelly Closes and seals on square or hex Kellys to rated working pressure

Packing Unit Closed on Open Hole Complete shutoff sealing up to rated working pressure

Operation Standard Surface Hookup Connects the secondary chamber to the opening chamber Hookup requires least amount of control fluid for fastest closing time Control pressure to closing chamber raises piston closing the packing unit to create seal-off Return flow from opening chamber splits to fill secondary chamber and balance flows to control system reservoir

Operating Curves Standard Surface Hookup GL 18-3/4 - 5000 MD Packing Unit Closing Pressure - Standard Hookup

Operation Optional Surface Hookup Connects the secondary chamber to the closing chamber Hookup requires least amount of closing pressure for optimum closing force. Control pressure to closing chamber and secondary chamber raises piston, closing the packing unit to create seal off. Return flow from opening chamber flows to control system reservoir.

Operating Curves Optional Surface Hookup

Stripping Operation Standard Surface Hookup Full seal-off while rotating or stripping of drill pipe and tool joints Slight leakage prolongs packing unit life by providing lubrication Slow tool joint stripping speeds reduce surge pressures Installation of surge absorber accumulator for faster closing pressure response

Stripping Operation Optional Surface Hookup Full seal-off while rotating or stripping of drill pipe and tool joints Slight leakage prolongs packing unit life by providing lubrication Slow tool joint stripping speeds reduce surge pressures Installation of surge absorber accumulator for faster closing pressure response

Subsea Operation Standard Hookup Hydrostatic Pressure of Drilling fluid column exerts opening force on BOP piston because of unbalanced areas Hydrostatic pressure of control fluid column has no effect on opening and closing chambers because they are of equal area Two hookup techniques provide means of compensating for the effects of the drilling fluid on the BOP piston Standard Hookup Secondary chamber connected to the opening chamber Optional Hookup Secondary chamber connected to the closing chamber Optional Hookup

Subsea Closing Pressure Comparison Chart

Standard Subsea Hookup Considered standard hookup for water depths to 800-1000’ Hookup requires least amount of control fluid thus gives the fastest closing time. This hookup requires an adjustment pressure P to be added to the surface closing pressure Closing pressure = PSC + P Where: PSC = surface closing pressure P = adjustment pressure

Standard Subsea Hookup (continued) Adjustment Pressure Calculation Adjustment Pressure P = (0.052 x Wm x Dw) - (0.45 x Dw)  Where: Wm = drilling fluid density in lb/gal Dw = water depth in ft 0.052 - conversion factor  = 2.19 = the ratio of closing chamber area to the secondary chamber area 0.45 psi/ft = pressure gradient of sea water, using a specific gravity of sea water = 1.04 0.433 psi/ft = pressure gradient of fresh water 2 methods to arrive at closing pressure 1. Calculation Add surface closing pressure from chart to calculated adjustment pressure 2. Using charts Add surface closing pressure from chart to adjustment pressure from chart

Standard Subsea Hookup (continued) Example Method 1 Drill pipe = 5” Well pressure = 3500 psi Drilling fluid = 16 lb/gal Water depth = 500 ft. Closing pressure = Psc + P Where: Psc = Surface closing pressure Psc = 560 psi from surface closing pressure chart for standard hookup Adjustment pressure P = (0.052 x 16 lb/gal x 500 ft) - (0.45 psi/ft x 500 ft) 2.19 P = 87 psi Psc + P = Pc 560 + 87 = 647 say 650 psi

Standard Subsea Hookup (continued) GL 18-3/4 5000 MD Packing Unit Closing Pressure Standard Hookup Method 2 From surface closing pressure = 560 psi From adjustment pressure P chart = 87 psi Closing Pressure PC = 647 psi Adjustment Pressure P Standard Hookup

Optional Subsea Hookup Recommended hookup for water depths below 3000’ Hookup requires from 14% to 28% less closing pressure This hookup also requires an adjustment pressure (P) to be added to surface closing pressure to compensate for hydrostatic pressure of drilling fluid column Closing pressure = surface closing pressure + adjustment pressure

Optional Subsea Hookup (continued) Adjustment Pressure Calculation Adjustment Pressure (P) =  [(0.052 X Wm X Dw) - (0.45 X Dw)]  Where: Wm = drilling fluid density in lb/gal Dw = water depth in ft 0.052 = conversion factor  = 2.19 = the ratio of closing chamber area to the secondary chamber area 0.45 psi/ft = pressure gradient of sea water, using a specific gravity of sea water = 1.04 0.433 psi/ft = pressure gradient of fresh water = 1.0  = __AC _ = Closing chamber area _ (AC + AS) Closing chamber area + Secondary chamber area Two methods to arrive at closing pressure 1. Calculation - Add surface closing pressure from chart to calculated adjustment pressure 2. Using charts - Add surface closing pressure from chart to adjustment pressure from chart

Optional Subsea Hook (continued) Example Method I Drill Pipe = 5” Well pressure = 3500 psi Drilling fluid = 16 lb/gal Water depth = 2000 ft Closing pressure = Psc + P Where: Psc = Surface closing pressure Psc = 384 psi from surface closing pressure chart for optional hookup Adjustment pressure P = 0.69[(0.052 x 16 lb/gal x 2000 ft) - (0.45 psi/ft x 2000 ft)] 2.19 P = 240 psi Psc + P = PC 384 + 240 = 624 say 625 psi

Optional Subsea Hookup (continued) Example Method 2 From surface closing pressure chart = 385 psi From adjustment pressure  P chart = 240 psi Closing pressure PC = 625 psi Adjustment Pressure  P Optional Hookup

Stripping Operation Subsea Standard Hookup Full seal-off while rotating or stripping of drill pipe and tool joints Slight leakage prolongs packing unit life by providing lubrication Slow tool joint stripping speeds reduce surge pressures Installation of surge absorber accumulator for faster closing pressure response

Standard Subsea Hookup Closing Chamber Surge Absorber Precharge Calculation: Pipe = 5” Water Depth = 500 ft Precharge PPC = 0.80 [surface closing pressure + (0.41 X Dw)] Where: Dw = water depth in ft 0.41 psi ft = Control fluid pressure gradient PSC = 400 psi = From closing pressure chart - surface standard hookup PPC = .80[400 + (0.41 X 500)] PPC = .80(400 + 205) PPC = .80 X 605 psi PPC = 485 psi

Stripping Operation Subsea Optional Hookup Full seal-off while rotating or stripping of drill pipe and tool joints Slight leakage prolongs packing unit life by providing lubrication Slow tool joint stripping speeds reduce surge pressures Installation of surge absorber accumulator for faster closing pressure response

Optional Subsea Hookup Closing Chamber Surge Absorber Precharge Calculation: Pipe = 5” Water Depth = 2000 ft Precharge PPC = 0.80 [surface closing pressure + (0.41 X Dw)] Where: Dw = Water depth in ft 0.41 psi ft = Control fluid pressure gradient PSC = 260 psi = From closing pressure chart - surface optional hookup PPC = .80[260 + (0.41 X 2000)] PPC = .80(260 + 820) PPC = .80 X 1080 PPC = 865 psi

Physical Data Engineering Data

Physical Data (continued) Bolt & Wrench Data

LL Long Life Packing Unit Packing Units Manufactured by Hydril High quality rubber compounds bonded to flanged steel segments Flanged steel segments anchor the packing unit and control rubber extrusion and flow during sealing Original Packing Unit LL Long Life Packing Unit

Packing Units (continued) Newest packing unit design for use in GL-18-3/4 5000 annular BOPs Better fatigue life Better stripping life 2 Compounds: Natural rubber Nitrile rubber MD Packing Unit

Packing Unit Replacement Pull Down Bolt Assembly Jaw Operating Screw Pipe Plug Sleeve Screw Jaw Head

Packing Unit Replacement (continued) Retract Jaw Operating Screws (4 turns counter clockwise)

Packing Unit Replacement (continued) Retract jaw operating screws 4 turns. This releases the jaws from the head. Remove 4 pull-down bolt assemblies from the top of the head.Lift off preventer head.

Packing Unit Replacement (continued) Lift out Packing Unit and Lubricate Piston Bowl

Packing Unit Replacement (continued) Install new Packing Unit Replace head Install pull-down bolt assemblies and pull head fully into place

Packing Unit Replacement (continued) Tighten jaw operating screws 4 turns and torque to 300-400 ft-lbs

Seals Dynamic Seals Static Seals Dynamic Seals - Hydril molded lip-type pressure energized design Static seals - O-ring or square design Seals molded from special synthetic rubber Dynamic Seals Static Seals

Maintenance 1. Inspect upper and lower connections 2. Check body 3. Inspect vertical bore 4. Check inner and outer body sleeve for wear 5. Check piston for wear or damage 6. Check wear plate 7. Inspect packing unit 8. Inspect seals

Seal Testing Hydril recommends all seals be replaced if a seal leak is suspected. 1. Test seals 18, 16, 23, & 14 a. Pressure closing chamber to 1000 psi (Packing unit closed on test pipe) b. Open opening chamber to atmosphere c. Open secondary chamber to atmosphere d. Pressurize well bore to 1000 psi IF: Well bore fluid (clean water or dyed water is seen at secondary chamber 1)Seal 18 is leaking, OR 2) Seal 23 is leaking, OR 3) Seal 18 and 23 are leaking IF: Closing fluid (milky colored water and soluble oil) is seen at secondary chamber--Seal 16 is leaking. IF: Closing fluid is seen at opening chamber--seal 14 is leaking. NOTE: Seals 14, 16 and 18 are 2-way seals and get tested in both directions.

Seal Testing (continued) 2. Test seals 18, 16, 23 a. Open closing chamber to atmosphere b. Open opening chamber to atmosphere c. Pressurize secondary chamber to 1500 psi (packing unit closed on test pipe) d. Well bore full of water at 0 pressure IF: Secondary chamber pressure gauge is dropping and well bore pressure gauge (below packing unit) is rising. 1) Seal 18 is leaking, OR 2) Seal 23 is leaking, OR 3) Seal 18 and 23 are leaking IF: Secondary chamber fluid is seen in closing chamber, seal 16 is leaking.

Seal Testing (continued) 3. Test Seals 14, 27 (lower) and 29 a. Open closing chamber to atmosphere b. Pressurize opening chamber to 1000 psi c. Secondary chamber is at 0 pressure and plugged (after application of opening chamber pressure) d. Well bore is empty IF: Opening fluid is seen at closing chamber, seal 14 is leaking. IF: Opening fluid is seen in well bore or coming from the relief valve. 1. Seal 27 (lower) is leaking, OR 2. Seal 29 is leaking, OR 3. Seal 27 (lower) and 29 are leaking.

Seal Testing (continued) 4. Test seal 27 (upper) a. Plug closing chamber b. Open opening chamber to atmosphere c. Plug secondary chamber d. Pressurize well bore to 1000 psi (requires blind flange on top, as packing unit is open) IF: Well bore fluid is seen at opening chamber, seal 27 (upper) is leaking. 5. Seals 2 and 3 are used primarily to exclude external matter and are not feasibly testable.

Packing Unit Testing Reliable packing unit testing achieved by measuring piston stroke. Maintain closing pressure during all seal-off operations Begin test with recommended closing pressure Measure piston stroke through opening in the head - Use 5/16 rod Maximum & minimum distance from top of head to top of piston stamped in the head Record piston stroke

Disassembly Vent all pressures Remove head (1) Release jaws (10) by rotating jaw operating screw (4) counter clockwise 4 turns Remove pull-down bolt assemblies (32) Install three (2”- 4-1/2” NC) eyebolts Lift off head (1) Remove wear plate by removing 12 cap screws (35 & 36) Remove packing unit (11) Install two (5/8” 11 NC) eyebolts Lift out packing unit (11) Remove opening chamber head (24) Install three (7/8” 9 UNC) eyebolts Install triple-line sling Lift out head (24)

Disassembly (continued) Remove piston (12) Install two piston lifting devices Install two-line sling Lift piston (12) Do not use air or gas Low pressure hydraulic pressure (50 psi) may be used

Disassembly (continued) Remove slotted body sleeve (20) Remove 14 cap screws (19) Lift out slotted body sleeve (20) Remove outer body sleeve (21) Install two (3/4”-10 NC) eye bolts Lift out sleeve (21)

Disassembly (continued) Disassemble jaw operating screw assembly Remove pipe plug (7) Remove sleeve screw and spacer sleeve (5 & 6) Remove jaw operating screw (4) Remove jaw from inside the body (10) Assembly is the reverse Pull Down Bolt Assembly Jaw Operating Screw Pipe Plug Sleeve Screw Jaw Head

Assembly Clean & inspect all parts Install slotted body sleeve and outer body sleeve (20 & 21) Install O-ring in seal groove (18) at bottom of outer body sleeve Lubricate O-ring thoroughly Install inner double U-seal (23) and inner non-extrusion rings (22) Install outer body sleeve (21) Install slotted body sleeve (2) Install 14 cap screws (19) Remove eyebolts from outer body sleeve

Assembly (continued) Install piston (12) Install lower double U-seal (16) and lower non-extrusion rings (15) Lubricate seals before installation Install middle double U-seal (14) and middle non-extrusion rings (13) Lubricate seals before installation Lubricate internal mating body surfaces Carefully lower piston into body Remove piston eyebolt assemblies

Assembly (continued) Install opening chamber head (24) Install square head gasket (29) Install U-seal (27) Install three (7/8” - 9 NC) eye bolts Install three-line sling Install opening chamber head

Assembly (continued) Install packing unit (11) Lubricate piston bowl Install two (5/8” - 11 NC) eyebolts Lift in packing unit Install BOP head (1) Install wear plate (35) with 12 cap screws (36) torque 20 ft-lbs Install O-ring (2) Install U-seal (27) Install three (2” - 4-1/2 NC) eyebolts Lift head in place Install pull-down bolt assemblies Ensure head & body clearance 0.5” (32) Rotate jaw operating screws (4) 4 turns clockwise 300-400 ft-lbs torque

Position of Parts

Position of Parts

Parts Identification