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

2. 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.

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

10. 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

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

12. 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.

13. Operating Curves Optional Surface Hookup

14. 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

15. 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

16. 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

17. Subsea Closing Pressure Comparison Chart

18. Standard Subsea Hookup
Considered standard hookup for water depths to ’
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

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/gal Dw = water depth in ft conversion factor  = = the ratio of closing chamber area to the secondary chamber area psi/ft = pressure gradient of sea water, using a specific gravity of sea water = 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

20. 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)
P = 87 psi Psc + P = Pc = 647 say 650 psi

21. Standard Subsea Hookup (continued)
GL 18-3/ 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

22. 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

23. 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 = 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 = 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

24. 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 = [(0.052 x 16 lb/gal x 2000 ft) - (0.45 psi/ft x 2000 ft)]
P = 240 psi Psc + P = PC = 624 say 625 psi

25. 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

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 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 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( )
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 ft Precharge PPC = 0.80 [surface closing pressure + (0.41 X Dw)]
Where: Dw = Water depth in ft 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( )
PPC = .80 X 1080
PPC = 865 psi

30. Physical Data
Engineering Data

31. Physical Data (continued) Bolt & Wrench Data

32. 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

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

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

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 ft-lbs

40. 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

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 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 to exclude external matter and are not feasibly 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 the head - Use 5/16 rod
Maximum & minimum distance from top of head to 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 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)

48. 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

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. 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

51. 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

52. 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

53. 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

54. 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 ft-lbs torque

55. Position of Parts

56. Position of Parts

57. Parts Identification