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

®. GL 18-3/4” 5,000 psi Annular Blowout Preventer. Definitions. Blowout Preventer (BOP)

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

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  1. ® GL 18-3/4” 5,000 psiAnnular Blowout Preventer

  2. Definitions Blowout Preventer (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.

  3. 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

  4. 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

  5. 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

  6. 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

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

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

  9. Packing UnitClosed on Open Hole • Complete shutoff sealing up to rated working pressure

  10. OperationStandard 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

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

  12. OperationOptional 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.

  13. Operating CurvesOptional Surface Hookup

  14. Stripping OperationStandard 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

  15. Stripping OperationOptional 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

  16. Subsea Operation • 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 HookupSecondary chamber connected to the opening chamber • Optional HookupSecondary chamber connected to the closing chamber Standard Hookup Optional Hookup

  17. Subsea Closing PressureComparison Chart

  18. 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 + PWhere:PSC = surface closing pressure P = adjustment pressure

  19. 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/galDw = water depth in ft0.052 - conversion factor = 2.19 = the ratio of closing chamber area to the secondary chamber area0.45 psi/ft = pressure gradient of sea water, using a specific gravity of sea water = 1.040.433 psi/ft = pressure gradient of fresh water 2 methods to arrive at closing pressure1. Calculation Add surface closing pressure from chart to calculated adjustment pressure2. Using charts Add surface closing pressure from chart to adjustment pressure from chart

  20. Standard Subsea Hookup(continued) Example Method 1 Drill pipe = 5”Well pressure = 3500 psiDrilling fluid = 16 lb/galWater 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 psiPsc + P = Pc560 + 87 = 647 say 650 psi

  21. 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 Pchart = 87 psi Closing Pressure PC = 647 psi Adjustment Pressure P Standard Hookup

  22. Optional Subsea Hookup • Recommended hookup for water depths below 3000’ • Hookup requires from14% 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

  23. Optional Subsea Hookup(continued) Adjustment Pressure CalculationAdjustment Pressure (P) =  [(0.052 X Wm X Dw) - (0.45 X Dw)] Where:Wm = drilling fluid density in lb/galDw = water depth in ft0.052 = conversion factor = 2.19 = the ratio of closing chamber area to the secondary chamber area0.45 psi/ft = pressure gradient of sea water, using a specific gravity of sea water = 1.040.433 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 pressure1. Calculation - Add surface closing pressure from chart to calculated adjustment pressure2. Using charts - Add surface closing pressure from chart to adjustment pressure from chart

  24. Optional Subsea Hook(continued) Example Method IDrill Pipe = 5”Well pressure = 3500 psiDrilling fluid = 16 lb/galWater depth = 2000 ft Closing pressure = Psc + PWhere: 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 psiPsc + P = PC384 + 240 = 624 say 625 psi

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

  26. 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

  27. Standard Subsea HookupClosing Chamber Surge Absorber Precharge Calculation:Pipe = 5”Water Depth = 500 ftPrecharge 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

  28. 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

  29. Optional Subsea Hookup Closing Chamber Surge Absorber Precharge Calculation:Pipe = 5”Water Depth = 2000 ftPrecharge 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

  30. Physical Data Engineering Data

  31. Physical Data (continued)Bolt & Wrench Data

  32. 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

  33. 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 rubberNitrile rubber MD Packing Unit

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

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

  36. 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.

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

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

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

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

  41. 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

  42. 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.

  43. 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.

  44. 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.

  45. 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 toexclude external matter and are notfeasibly testable.

  46. 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 thehead - Use 5/16 rod • Maximum & minimum distance from top of headto top of piston stamped in the head • Record piston stroke

  47. Disassembly • Vent all pressures • Remove head (1) • Release jaws (10) by rotating jaw operating screw (4) counter clockwise4 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)

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

  49. 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)

  50. Pull Down Bolt Assembly Jaw Operating Screw Pipe Plug Sleeve Screw Jaw Head 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

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