®
GL 18-3/4” 5,000 psi
Annular Blowout Preventer
1
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.
2
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
3
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
4
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
5
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
6
Packing Unit - Closed on Pipe
 Closed on drill pipe
 Seals on tool joints,
pipe, casing, tubing or
wire line to rated
working pressure
7
Packing Unit - Closed on Kelly
 Closes and seals on
square or hex Kellys
to rated working
pressure
8
Packing Unit
Closed on Open Hole
 Complete shutoff
sealing up to rated
working pressure
9
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
10
Operating Curves
Standard Surface Hookup
GL 18-3/4 - 5000 MD Packing Unit Closing Pressure Standard Hookup
11
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.
12
Operating Curves
Optional Surface Hookup
13
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
14
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
15
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
Optional Hookup
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
16
Subsea Closing Pressure
Comparison Chart
MD Packing Unit
GL 18-3/4" 5,000 psi: 5" drill pipe; 5,000 psi well pressure; 16 lb/gal drilling fluid
Water
Depth Ft.
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
*Closing Pressure psi
Standard Hook-up
640
730
815
905
990
1075
1165
1250
1340
1425
1515
*Closing Pressure psi
Optional Hook-up
440
530
615
700
790
875
965
1050
1140
1225
1310
* All pressures have been rounded up to the nearest 5 psi.
17
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 = P
SC
+ P
Where:
PSC = surface closing pressure
P = adjustment pressure
18
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
19
Standard Subsea Hookup
(continued)
Example Method 1
Drill pipe
Well pressure
Drilling fluid
Water depth
=
=
=
=
5”
3500 psi
16 lb/gal
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
20
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
21
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
22
Optional Subsea Hookup
(continued)
Adjustment Pressure Calculation
Adjustment Pressure (P) =  [(0.052 X Wm X Dw) - (0.45 X Dw)]

Where:
Wm
Dw
0.052
 = 2.19
=
=
=
=
0.45 psi/ft =
0.433 psi/ft =
 = __AC _
(AC + AS)
=
drilling fluid density in lb/gal
water depth in ft
conversion factor
the ratio of closing chamber area
to the secondary chamber area
pressure gradient of sea water,
using a specific gravity of sea water = 1.04
pressure gradient of fresh water = 1.0
Closing chamber area
_
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
23
Optional Subsea Hook
(continued)
Example Method I
Drill Pipe
Well pressure
Drilling fluid
Water depth
=
=
=
=
5”
3500 psi
16 lb/gal
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
24
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
25
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
26
Standard Subsea Hookup
Closing Chamber Surge Absorber Precharge
Calculation:
Pipe
=
Water Depth
=
Precharge PPC =
Where:
Dw
=
0.41 psi ft =
PSC = 400 psi =
5”
500 ft
0.80 [surface closing pressure + (0.41 X Dw)]
water depth in ft
Control fluid pressure gradient
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
27
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
28
Optional Subsea Hookup
Closing Chamber Surge Absorber Precharge
Calculation:
Pipe
Water Depth
Precharge PPC
Where: Dw
0.41 psi ft
PSC = 260 psi
=
=
=
=
=
=
5”
2000 ft
0.80 [surface closing pressure + (0.41 X Dw)]
Water depth in ft
Control fluid pressure gradient
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
29
Physical Data
Engineering Data
30
Physical Data (continued)
Bolt & Wrench Data
31
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
32
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
33
Packing Unit Replacement
Pull Down Bolt Assembly
Jaw Operating Screw
Pipe Plug
Sleeve Screw
Jaw
Head
34
Packing Unit Replacement (continued)
Retract Jaw Operating Screws
(4 turns counter clockwise)
35
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.
36
Packing Unit Replacement
(continued)
Lift out Packing Unit and Lubricate Piston Bowl
37
Packing Unit Replacement
(continued)
Install new Packing
Unit
Replace head
Install pull-down bolt
assemblies and pull
head fully into place
38
Packing Unit Replacement
(continued)
Tighten jaw operating screws 4 turns and
torque to 300-400 ft-lbs
39
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
40
Maintenance
1.
2.
3.
4.
5.
6.
7.
8.
Inspect upper and lower connections
Check body
Inspect vertical bore
Check inner and outer body sleeve for wear
Check piston for wear or damage
Check wear plate
Inspect packing unit
Inspect seals
41
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.
42
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.
43
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.
44
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.
45
Packing Unit Testing
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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
46
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)
47
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
48
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)
49
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
50
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
51
Assembly (continued)
 Install piston (12)
 Install lower double
U-seal (16) and lower nonextrusion rings (15)
Lubricate seals before
installation
 Install middle double
U-seal (14) and middle nonextrusion rings (13)
Lubricate seals before
installation
 Lubricate internal mating body
surfaces
 Carefully lower piston into body
 Remove piston eyebolt
assemblies
52
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
53
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
54
Position of Parts
55
Position of Parts
56
Parts Identification
57