gl abop training

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GL 18-3/4” 5,000 psiGL 18-3/4” 5,000 psiAnnular Blowout PreventerAnnular Blowout Preventer

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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 BOPA BOP that uses a shaped elastomeric sealing element to seal the space between the tubular and the wellbore or an open hole.

DefinitionsDefinitions

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Hydril GL ABOPHydril 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

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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

Hydril GL ABOPHydril GL ABOP

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Piston OperationPiston 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

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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 - Fully OpenPacking Unit - Fully Open

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Packing Unit - Closed on PipePacking Unit - Closed on Pipe

Closed on drill pipe

Seals on tool joints, pipe, casing, tubing or wire line to rated working pressure

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Packing Unit - Closed on KellyPacking Unit - Closed on Kelly

Closes and seals on square or hex Kellys to rated working pressure

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Packing UnitPacking UnitClosed on Open HoleClosed on Open Hole

Complete shutoff sealing up to rated working pressure

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OperationOperationStandard Surface HookupStandard 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

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Operating CurvesOperating CurvesStandard Surface HookupStandard Surface Hookup

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

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OperationOperationOptional Surface HookupOptional 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.

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Operating CurvesOperating CurvesOptional Surface HookupOptional Surface Hookup

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Stripping OperationStripping OperationStandard Surface HookupStandard 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

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Stripping OperationStripping OperationOptional Surface HookupOptional Surface Hookup





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Subsea OperationSubsea 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

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Subsea Closing PressureSubsea Closing PressureComparison ChartComparison Chart

0 640 440500 730 530

1000 815 6151500 905 7002000 990 7902500 1075 8753000 1165 9653500 1250 10504000 1340 11404500 1425 12255000 1515 1310

* All pressures have been rounded up to the nearest 5 psi.

MD Packing Unit

Depth Ft.Water

GL 18-3/4" 5,000 psi: 5" drill pipe; 5,000 psi well pressure; 16 lb/gal drilling fluid

*Closing Pressure psiStandard Hook-up

*Closing Pressure psiOptional Hook-up

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Standard Subsea HookupStandard 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

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Standard Subsea HookupStandard Subsea Hookup(continued)(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

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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 = Pc

560 + 87 = 647 say 650 psi560 + 87 = 647 say 650 psi

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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

GL 18-3/4 5000 MD Packing Unit Closing PressureStandard Hookup

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Optional Subsea HookupOptional 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

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Optional Subsea HookupOptional Subsea Hookup(continued)(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

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Optional Subsea HookOptional Subsea Hook(continued)(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 = PC

384 + 240 = 624 say 625 psi384 + 240 = 624 say 625 psi

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Optional Subsea HookupOptional Subsea Hookup(continued)(continued)

From surface closing pressure chart = 385 psi

From adjustment pressure P chart = 240 psi

Closing pressure PC = 625 psi

Adjustment Pressure P Optional Hookup

Example Method 2

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Stripping Operation Subsea Stripping Operation Subsea Standard HookupStandard Hookup





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Standard Subsea HookupStandard Subsea HookupClosing Chamber Surge Absorber PrechargeClosing 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 ft0.41 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

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Stripping Operation Subsea Stripping Operation Subsea Optional HookupOptional Hookup





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Calculation:Pipe = 5”Water Depth = 2000 ftPrecharge PPC = 0.80 [surface closing pressure + (0.41 X Dw)]

Where: Dw = Water depth in ft0.41 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

Optional Subsea HookupOptional Subsea HookupClosing Chamber Surge Absorber Precharge

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Physical DataPhysical Data

Engineering Data

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Physical Data Physical Data (continued)(continued)

Bolt & Wrench DataBolt & Wrench Data

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Packing UnitsPacking 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

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Packing Units Packing Units (continued)(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

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Packing Unit ReplacementPacking Unit Replacement

Pull Down Bolt Assembly

Jaw Operating Screw

Pipe Plug

Sleeve Screw

Jaw

Head

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Packing Unit Replacement Packing Unit Replacement (continued)(continued)

Retract Jaw Operating Screws (4 turns counter clockwise)

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Packing Unit Replacement Packing Unit Replacement (continued)(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.

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Packing Unit ReplacementPacking Unit Replacement (continued)(continued)

Lift out Packing Unit and Lubricate Piston Bowl

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Install new Packing Unit

Replace head

Install pull-down bolt assemblies and pull head fully into place

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Tighten jaw operating screws 4 turns and torque to 300-400 ft-lbs

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SealsSeals

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

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MaintenanceMaintenance

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

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Seal TestingSeal TestingHydril 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 atmospherec. Open secondary chamber to atmosphered. Pressurize well bore to 1000 psiIF: Well bore fluid (clean water or dyed water

is seen at secondary chamber1)Seal 18 is leaking, OR2) Seal 23 is leaking, OR3) Seal 18 and 23 are leaking

IF: Closing fluid (milky colored water andsoluble oil) is seen at secondarychamber--Seal 16 is leaking.

IF: Closing fluid is seen at openingchamber--seal 14 is leaking.

NOTE: Seals 14, 16 and 18 are 2-way seals and get tested in both directions.

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Seal Testing Seal Testing (continued)(continued)

2. Test seals 18, 16, 23a. Open closing chamber to atmosphereb. Open opening chamber to atmospherec. Pressurize secondary chamber to

1500 psi (packing unit closed on test pipe)d. Well bore full of water at 0 pressureIF: Secondary chamber pressure gauge is

dropping and well bore pressure gauge(below packing unit) is rising.1) Seal 18 is leaking, OR2) Seal 23 is leaking, OR3) Seal 18 and 23 are leaking

IF: Secondary chamber fluid is seenin closing chamber, seal 16 is leaking.

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3. Test Seals 14, 27 (lower) and 29a. Open closing chamber to atmosphereb. Pressurize opening chamber to 1000 psic. Secondary chamber is at 0 pressure and

plugged (after application of openingchamber pressure)

d. Well bore is emptyIF: 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, OR2. Seal 29 is leaking, OR3. Seal 27 (lower) and 29 are leaking.

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4. Test seal 27 (upper)a. Plug closing chamberb. Open opening chamber to

atmospherec. Plug secondary chamberd. Pressurize well bore to 1000 psi

(requires blind flange on top, aspacking unit is open)

IF: Well bore fluid is seen at openingchamber, seal 27 (upper) is

leaking.5. Seals 2 and 3 are used primarily to

exclude external matter and are notfeasibly testable.

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Packing Unit TestingPacking 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

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DisassemblyDisassembly

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)

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Disassembly Disassembly (continued)(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

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Disassembly Disassembly (continued)(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)

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Disassembly Disassembly (continued)(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

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AssemblyAssembly

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

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Assembly Assembly (continued)(continued)

Install piston (12) Install lower double

U-seal (16) and lower non-extrusion rings (15)Lubricate seals before installation

Install middle doubleU-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

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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

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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

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Position of PartsPosition of Parts

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Position of PartsPosition of Parts

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Parts IdentificationParts Identification

gl abop training

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