2010 01 Equipment Training Rev1

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Well ControlEquipment


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Well Control ManualWell Control Manual

Manual standard clause

This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and isonly for the use for course conducted by Maersk Training.

This manual shall not affect the legal relationship or liability of Maersk Training with or toany third party and neither shall such third party be entitled to reply upon it.

Maersk Training shall have no liability for technical or editorial errors or omissions in thismanual; nor any damage, including but not limited to direct, punitive, incidental, orconsequential damages resulting from or arising out of its use.

No part of this manual may be reproduced in any shape or form or by any meanselectronically, mechanically, by photocopying, recording or otherwise, without the prior

permission of Maersk Training.

Copyright © Maersk Training A/S 2010-January

Prepared by NLN & JOA

Modified & printed 2010 July

Modified by MJB

Approved by JOA

Address Maersk Training A/SDyrekredsen 4. RantzausmindeDK - 5700 SvendborgDenmark

E-mail: [email protected]

Homepage www.maersktraining.com

Internal reference 2010_01_Equipment_Training_rev1.docx


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Table of contents:

Section 01 Well control barri ers. ................................................................................. 4

01.01 Primary well control barrier. ............................................................................ 4 01.02 Secondary well control barrier. ........................................................................ 4

Section 02 BOP conf iguration ..................................................................................... 5

02.01 Bop stack arrangements ................................................................................. 5 02.02 Stack component codes .................................................................................. 5 02.03 Drilling spools .................................................................................................. 6

Section 03 Diverter systems ........................................................................................ 8

03.01 Purpose of diverter system (API RP53 4.1) .................................................... 8 03.02 Diverter equipment (API RP53 4.2.2) .............................................................. 8 03.03 Guidelines for diverting with string on bottom ............................................... 11 03.04 Guidelines for diverting with string off bottom ............................................... 11 03.05 Rotating head ................................................................................................ 11 03.06 Diverter control system ................................................................................. 13

Section 04 Annular p reventers .................................................................................. 14

04.00 Definition (API RP53 3.1.2) ........................................................................... 14 04.01 General ......................................................................................................... 14 04.02 Testing .......................................................................................................... 14 04.03 Pressure test frequency ................................................................................ 16 04.04 Accumulator response time........................................................................... 16 04.05 Hydril annular preventers .............................................................................. 16 04.06 Shaffer annular preventers ........................................................................... 21 04.07 Cameron annular preventer .......................................................................... 23 04.08 Packing unit .................................................................................................. 24

Section 05 Ram pr eventers ........................................................................................ 25

05.00 General ......................................................................................................... 25 05.01 Testing .......................................................................................................... 26 05.02 Pressure test frequency ................................................................................ 27 05.03 Accumulator response time (API RP53 12.3.3) ............................................. 27

05.04

Cameron ram preventer ................................................................................ 28

05.05 Ram locking systems .................................................................................... 31 05.06 Cameron ram assembly ................................................................................ 36 05.07 Operating ratio .............................................................................................. 39 05.08 BOP end and side outlet Connections .......................................................... 41 05.09 API type flanges ............................................................................................ 41 05.10 Ring joint gaskets and grooves ..................................................................... 43

Section 06 Choke mani fold ........................................................................................ 47

06.01 General ......................................................................................................... 47 06.02 Choke manifold – installation ........................................................................ 47

06.03

Choke lines – installation .............................................................................. 48

06.04 Kill lines – installation .................................................................................... 48 06.05 BOP – Side outlet valves .............................................................................. 49 06.06 Chokes .......................................................................................................... 49


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06.07 Hydrates........................................................................................................ 51 06.08 Mud/gas separator ........................................................................................ 52 06.09 Degasser....................................................................................................... 54

Section 07 Auxi li ary equipment ................................................................................ 55 07.01 Kelly valves ................................................................................................... 55 07.02 Top drive valves ............................................................................................ 55 07.03 Drillpipe safety valve (DPSV) ........................................................................ 56 07.04 Inside blowout preventer (IBOP) ................................................................... 56 07.05 Drillstring float valve ...................................................................................... 56 07.06 Tester plug .................................................................................................... 57 07.07 Cup type tester plug ...................................................................................... 58 07.08 Triptank ......................................................................................................... 58 07.09 Pit volume measuring devices ...................................................................... 58

07.10

Flow rate sensor ........................................................................................... 58

Section 08 Subsea BOP stack components ............................................................. 59

08.01 Model 70 Collet Connector (Cameron Iron Works) ....................................... 60 08.02 Model HC Collet Connector (Cameron Iron Works) ...................................... 62 08.03 Hydraulic operated choke/kill line valves ...................................................... 63

Section 09 Dril ling riser and related components ................................................... 64

09.01 Flex/Ball joint ................................................................................................. 65 09.02 Telescopic joint ............................................................................................. 66 09.03 Riser fill-up valve ........................................................................................... 67

09.04

Mechanical riser coupling ............................................................................. 67

Section 10 Hydraulic BOP control sys tem components (Subsea) ......................... 68

10.01 Subsea hose bundle storage reels ................................................................ 69 10.02 Manifolds on the Subsea hose bundle storage reels .................................... 70 10.03 Subsea hose (Umbilical) ............................................................................... 70 10.04 Subsea control pods (blue and yellow) ......................................................... 71 10.05 Shuttle valves ................................................................................................ 72


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Section 01 Well cont rol barriers.

01.01 Primary well control barri er.

During normal drilling operation it will always be the hydrostatic pressure of the drilling fluidthat creates the primary barrier to avoid any flow of formation fluid into the well bore. If forany reason the primary barrier is lost the well control equipment together with the drillingfluid in the well bore will be the secondary barrier. This will allow us to re-establish theprimary barrier on a safe and efficient way.

01.02 Secondary well control barrier.

The well control equipment must be able to close and secure the well under allcircumstances. Further to that circulation of heavy drilling fluid into the well bore and

formation fluid out of the well bore under controlled manner must be possible.

The well control equipment should be able to close on open hole(without tubular), aroundBHA and other tubular used in the drilling operation. It should also be able to cut the drillstring or lighter tubular and seal the well bore and allow the drill string to be hanged off onthe pipe rams or stripped into the well bore.

To avoid single components to create total failure of the system a contingency (back up)function should be build into the system.

All well control equipment must be maintained, function- and pressure tested according to

company policy and procedures to assured correct function and integrity when required.

With the well closed in and the drill string in the well bore, formation pressure can beobtained through the drill string by adding SIDPP with pressure hydrostatic.

To secure the drill string and obtain integrity following barriers can be used:

DPSV (drill pipe safety valve)DIBPV (drop In back pressure valve (dart, landing sub and retrieving tool)IBOP (inside blow-out preventer)Fast shut off coupling with DPSVCheck valves (Drill pipe floats)

To secure the annulus and obtain integrity following barriers can be used:

Annular PreventerRam PreventerShear/Blind Ram

During normal dri lling operation two barriers must always be in place where thehydrostatic head of the drilling fluid is one and the BOP stack the other.


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Section 02 BOP conf iguration

02.01 Bop stack arrangements

Example arrangements for BOP equipment are based on rated working pressures.Example stack arrangements shown in Fig. 01 & 02 should prove adequate in normalenvironments, for rated working pressures of 2K, 3K, 5K, IOK, 15K, and 20K.

Arrangements other than those illustrated may be equally adequate in meeting wellrequirements and promoting safety and efficiency.

Rated wor king pressure

2K 2000 psi (13.8 MPa)3K 3000 psi (20.7 MPa)

5K 5000 psi (34.5 MPa)10K 10000 psi (69.0 MPa)15K 15000 psi (103.5 MPa)20K 20000 psi (138.0 MPa)

Fig 01 Fig 02

02.02 Stack component codes

Every installed ram BOP should have, as a minimum, a working pressure equal to themaximum anticipated surface pressure to be encountered. The recommended componentcodes for designation of BOP stack arrangement are as follows:

G = Rotating head.

A = Annular type BOP.

R = Single ram type BOP with one set of rams, either blank or for pipe, asoperator prefers.

RD = Double ram type BOP with two sets of rams, positioned in accordance withoperator's choice.


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RT = Triple ram type BOP with three sets of rams, positioned in accordance withoperator's choice.

S = Drilling spool with side outlet connection for choke and kill lines.

C = Hydraulic well head connector with a minimum rated working pressure equalto the BOP stack rated working pressure.

K = 1000 psi rated working pressure.

BOP components are typically described upward from the uppermost piece of permanentwellhead equipment, or from the bottom of the BOP stack. A BOP stack may be fully iden-tified by a very simple designation, such as:

15K - 13 5/8 – RSRRAG

This BOP stack would be rated 15.000 psi (103,5 MPa) working pressure, withthroughbore of 13-5/8 inch (34,61 cm) and would be arranged as in Figure 02B.

Annular BOPs may have a lower rated work ing pressure than the ram BOPs.

02.03 Drilling spools

Choke and kill lines may be connected either to side outlets of the BOPs, or to a drillingspool installed below at least one BOP capable of closing on pipe. Utilization of the BOPside outlets reduces the number of stack connections and overall BOP stack height.

However, a drilling spool is used to provide stack outlets (to localize possible erosion in theless expensive spool) and to allow additional space between preventers to facilitatestripping, hang off, and/or shear operations. See Fig 03

Fig 03

Drilling spools for BOP stacks should meet the following minimum specifications:1. 3K and 5K arrangements should have two side outlets no smaller than a 2-inch

(5.08 cm) nominal diameter and be flanged, studded, or hubbed. IOK, 15K, and20K arrangements should have two side outlets, one 3-inch (7.62 cm) and one 2-inch (5.08 cm) nominal diameter as a minimum, and be flanged, studded, orhubbed.


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2. Have a vertical bore diameter the same internal diameter as the mating BOPs andat least equal to the maximum bore of the uppermost casing/tubing head.

3. Have a rated working pressure equal to the rated working pressure of the installedram BOP.

Note: For drilli ng operations, wellhead outlets should not be employed for choke- orkill l ines.


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Section 03 Diverter systems

Fig 04

03.01 Purpose of diverter system (API RP53 4.1)

A diverter system is often used during top-hole drilling. A diverter is not designed to shut in

or halt flow, but rather permits routing of the flow away from the rig. The diverter is used toprotect the personnel and equipment by re-routing the flow of shallow gas and wellborefluids emanating from the well to a remote vent line (see Fig 04). The system deals withthe potentially hazardous flows that can be experienced prior to setting the casing stringon which the BOP stack and choke manifold will be installed. The system is designed topack-off around the Kelly, drill string, or casing to divert flow in a safe direction. Divertershaving annular packing units can also close on wire line and open hole. Valves in thesystem direct the well flow when the diverter is actuated. The function of the valves maybe integral to the diverter unit.

03.02 Diverter equipment (API RP53 4.2.2)

The diverter system consists of a low pressure diverter or an annular preventer ofsufficient internal bore to pass the bit required for subsequent drilling. Vent line(s) ofadequate size [6 inches (15.24 cm) or larger] are attached to outlets below the diverter andextended to a location(s) sufficiently distant from the well to permit safe venting.

Conventional annular BOPs (see Fig 05), insert-type diverters (see Fig 06), or rotatingheads (see Fig 10) can be used as diverters. The rated working pressure of the diverterand vent line(s) are designed and sized to permit diverting of well bore fluids whileminimizing wellbore back pressure. Vent lines are typically 10 inches (25.4 cm) or larger IDfor offshore and 6 inches (15.24 cm) or larger ID for onshore operations.


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Fig 06

Fig 05

If the diverter system incorporates a valve(s) on the vent line(s), (refer to APIRecommended practice 64), this valve(s) should be full opening and full bore (have atleast the same opening as the line in which they are installed). The system should behydraulically controlled such that at least one vent line valve is in the open position beforethe diverter packer closes.

Diverter test ing (API RP53 4.2.5)The diverter and all valves should be function tested when installed and at appropriatetimes during operations to determine that the system will function properly.(See also API RP 53 17.4)

CAUTION: Fluid should be pumped through the diverter and each diverter vent line atappropriate times during operations to ascertain the line(s) is not plugged. Inspection andclean-out ports should be provided at all low points in the system. Drains and/or heattracings may he required in colder climates.

The hydraulic supply pressure to the diverter control panel is routed directly from thehydraulic control unit with 3.000 psi.

Older types of diverter systems have separate operating handles for each components asseen in Fig 07, but most have now been changed so the valves is integral to the diverterunit.


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Fig 07

To operate the system in Fig 07 the following sequence must be used to avoid shutting inor halt the flow from the well bore:

1. Open B or C depending on wind direction2. Close E3. Close A

In the Hydril model FS21-500 the diverter is integral to an annular preventer and is only

equipped with one diverter line witch is diverted into two lines by a DS12-500 FlowSelector valve that makes it possible to divert fluid and gas to either side of the rigdepending of wind direction or to both side at the same time. See Fig 08 and 09.

Fig 08 Fig 09


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03.03 Guidelines for diverting with str ing on bottom

1. Route returns to downwind vent line and close diverter

2. Pump at maximum rate and switch to kill fluid without stopping the pumps. If no killfluid available, use sea water. (Do not stop the pumps)

3. If the diverter system fails before control of the well is regained or broaching tosurface occurs, evacuate all personnel and leave the mud pumps running on seawater at maximum pump rate.

03.04 Guidelines for diverting with str ing off bottom

If it becomes necessary to divert gas, water and/or sand debris, route returns to downwind

vent line and close diverter.

1. Do not stop pumping and if mud reserves run out, keep pumping seawater atmaximum rate. Do not stop the pumps.

2. Arrange emergency evacuation of all non-essential personnel and prepareevacuation of remaining personnel.

3. If the diverter system fails before control of the well is regained, or broaching tosurface occurs, evacuate all personnel and leave the mud pumps running onseawater at maximum pump rate.

03.05 Rotating head

API RP 64 sect ion 3.1.80 A rotating head can be used as a diverter to complement a blowout preventer system. Thestripper rubber is energized by the wellbore pressure to seal against the drill pipe, kelly, orother pipe to facilitate diverting returned well fluids and can be used to permit pipemovement (reciprocating and or rotation).

The original equipment was designed for air drilling and later used for mud, gas andgeothermal applications. Later generation equipment was applied by industry for the flowdrilling applications that causes high pressures at the wellhead. The original design andengineering principles for its use still applies today. Within the BOP system the APIrecognizes the rotating head as a diverter. See Fig 10.

The rotating BOP is used on top of a regular BOP stack consisting of ram and annularBOPs.


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The rotating head seals off any shape ofkelly and will also seal on any type of drillpipe whether flush joint, upset or coupled.No special operations are required forhandling the pipe.

As the various elements of the drill stringare raised or lowered, the “stripper rubber”changes shape to conform to the OD ofthese elements. In this way the hole isclosed at all times. A flanged outlet belowthe stripper rubber allows flow underpressure to be directed out through the flowline.

Fig 10

The rotating b low-out preventer is ideal for use when:

• Drilling in H2S areas.• Circulating with air or gas.• Drilling under balanced. (UBD)• Drilling with reverse circulation.• Drilling in areas susceptible to blow-outs.• Drilling geothermal wells.

The rotating blow-out preventer consists of three major assemblies. See Fig 11.

• The rotating assembly• The body• Kelly drive uni

The body is flanged to the top of the blow-outpreventer and the rotating assembly is locked inwith a quick release mechanism. The kelly driveunit is installed on the kelly and turns the

rotating sleeve that has the stripper rubberattached to the lower end. The stripper rubberseals off the well pressure between the annulusof the hole and the outside of the drill pipe. Therotating sleeve packing effectively sealsbetween the outside of the rotating sleeve androtating assembly housing.

The stripper rubber is constructed in suchmanner that as the well pressure increase, thestripper forms a tighter seal.

Fig 11

Some rotating heads is build with hydraulic pressurised stripping rubbers.


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Underbalanced drilling is now being more widely reborn in the oil and gas industry. Themajor advances of underbalanced drilling is to lower costs, reduce drilling days, reducedifferential sticking problems and hole drag caused by mud cake.

Because underbalanced drilling creates the condition for fluid to flow from the formationinto the well bore, successful underbalanced drilling must include the selection of propercontrol equipment to handle the drilling fluid and formation fluids at surface. The rotatingcontrol head is one of the major elements of the system.

03.06 Diverter control system

The diverter control system should be designed to preclude closing-in the well with thediverter. This requires opening one or more vent lines prior to closing the diverter as wellas closing normally open mud system valves.

A diverter control system should be capable of operating the vent line and flow line valves(if any) and closing the annular packing element on pipe or open hole within thirty secondsof actuation if the packing element has a nominal bore of twenty inches or less. Forelements of more than twenty inches nominal bore, the diverter control system should becapable of operating the vent line and flow line valves (if any) and closing on pipe in usewithin forty-five seconds.

The diverter control system may be supplied with hydraulic control pressure from the BOPcontrol system. In this case there is usually more accumulator capacity, pump capacityand reservoir capacity than is required for the diverter system. These should, however,

comply with the recommendations which follow for a self-contained diverter control sys-tem. An isolation valve should be installed in the line from the main hydraulic supply toshut off the supply to the diverter control system when it is not in use. The function of thisvalve should be clearly labeled and its position status should be clearly visible.

All of the diverter control functions should be operable from the rig floor. A second controlpanel should be provided in an area remote from the rig floor. The remote area panelshould be capable of operating all diverter system functions including any necessarysequencing and control of the direction of the diverted flow.


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Section 04 Annular preventers

04.00 Defini tion (API RP53 3.1.2)

An Annular Preventer is a device that can seal around any object in the wellbore or uponitself. Compression of reinforced elastomer packing element by hydraulic pressure effectsthe seal.

Note: This definition statement is wrong and will be adjusted in the future by API. Annularpreventers will not seal around blades of very large stabilizers, bit cones and rollers onroller reamers.

04.01 General

In this manual we are going to look at of some commonly used types of annular preventersin the industry. These preventers are used for subsea and/or surface applications and theyare fabricated by three different manufactures:

Cameron Cooper: Type “D”Type “DL”

Hydril: Model “GK”Model “GL”Model “GX”Model “MSP

Shaffer: Shaffer Spherical.

04.02 Testing

API RP53Visual Inspection of annular preventers:1. PackerVisually inspect condition of packer. Check for gouges in seal area. Verify and record ageof packer. Ensure within shelf life of manufacturer. Record drilling fluid and inquire aboutcompatible.

2. ThroughboreEnsure no key seat damage in annular cap wear band. Record if any.

3. DriftEnsure that the packer is fully open and not protruding into the wellbore.

4. Surge BottleCheck for proper nitrogen pre-charge in accumulator bottle. Consider water depth for sub-sea application.

5. MillingCheck for metal shavings if milling operations have been performed.


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6. Operating PressuresEnsure that a operating range pressure chart in relation to pipe size and wellbore pressureis posted.

7. Drift testDrift test the annular preventer to ensure that it returns to full open bore within 30 min.

Function test: API RP53 17.3.1 All operational components of the BOP equipment systems should be functioned at leastonce a week to verify the component's intended operations. Function tests may or may notinclude pressure tests.

• Function tests should be alternated from the driller's panel and from mini-remotepanels, if on location.

• Actuation times should be recorded as a data base for evaluating trends.

Pressure tests: API RP53 17.3.2.1 All blowout prevention components that may be exposed to well pressure should be testedfirst to a low pressure of 200 to 300 psi (1.38 to 2.1 MPa) and then to a high pressure.

• When performing the low pressure test, do not apply a higher pressure and bleeddown to the low test pressure. The higher pressure could initiate a seal that maycontinue to seal after the pressure is lowered and therefore misrepresenting a lowpressure condition.

• A stable low test pressure should be maintained for at least 5 minutes.

The initial high pressure test: Annular BOPs, with a joint of drill pipe installed, may betested to the test pressure applied to the ram BOP’s or to a minimum of 70 percent of theannular preventer working pressure, whichever is the lesser.

Initial pressure tests are defined as those tests that should be performed on locationbefore the well is spudded or before the equipment is put into operational service.

Subsequent high pressure tests : Annular BOP’s, with a joint of drill pipe installed,should be tested to a minimum of 70 percent of their working pressure or to the testpressure of the ram BOP’s, whichever is less.

Subsequent pressure tests are tests that should be performed at identified periods duringdrilling and completion activity on a well.

A stable high test pressure should be maintained for at least 5 minutes.With larger size annular BOP’s some small movement typically continues within the largerubber mass for prolonged periods after pressure is applied. This packer creep movementshould be considered when monitoring the pressure test of the annular.Pressure test operations should be alternately controlled from the various control stations.


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Pressure tests of hydraulic chambers API RP53 17.3.2.4The pressure test performed on hydraulic chambers of annular BOP’s should be to at least1,500 psi (10.3 MPa). The tests should be run on both the opening and the closingchambers. Pressure should be stabilized for at least 5 minutes.

Subsequent pressure tests are typically performed on hydraulic chambers only betweenwells or when the equipment is reassembled.

04.03 Pressure test frequencyPressure tests on the well control equipment should be conducted at least:

• Prior to spud or upon installation.• After the disconnection or repair of any pressure containment seal in the BOP

stack, choke line, or choke manifold, but limited to the affected component.• Not to exceed 21 days.

04.04 Accumulator response time

Response time between activation and complete operation of a function is based on BOPor valve closure and seal off. Closing time should not exceed 30 seconds for annularpreventers smaller than 18-3/4” nominal bore and 45 seconds for annular preventers of18-3/4” and larger. Measurement of closing response time begins at pushing the button orturning the control valve handle to operate the function and ends when the BOP or valve isclosed affecting a seal. A BOP may be considered closed when the regulated operatingpressure has recovered to its nominal setting.

04.05 Hydril annular preventers

Hydril GK annular preventer (See Fig 12)The “GK” annular blow-out preventer wasdesigned especially for surface installationsand is also used on offshore platforms andsub-sea. The “GK” is a universal annularblow-out preventer with a long record ofproven performance.

• Only three major components.• Only two moving parts.

Closing pressure should be reduced aswellbore pressure increases in order toprevent excessive closing force.

Standard operation requires both opening and closing pressure. Seal off is effected by

hydraulic pressure applied to the closing chamber which raises the piston, forcing thepacking unit into a sealing engagement.

Fig 12


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The “GK” is designed to be well pressure assisted in maintaining packing unit seal off onceinitial seal off has been affected. As well bore pressure further increase closure ismaintained by well pressure alone.

Hydril GL annular preventer (See Fig 13)

The Hydril GL annularpreventers aredesigned anddeveloped for subseaand surface operations.The packing unitprovides full closure atRated Working

Pressure on open holeand on most items inthe wellbore - casing,drill pipe, tool joints,kelly or tubing.The special design ofthe Hydril GL makes itsuited for subsea anddeep water drilling.These drillingconditions demand

long-life packingelements for drill pipe stripping operations and frequent testing.

The secondary chamber, which is unique for the GL BOP, provides this unit with greatflexibility of hydraulic control hook-up.

The chamber can be connected in two waysto optimise operations for different effects,either to minimise closing/opening fluidvolumes or to reduce closing pressure.

Connecting the secondary chamber (Fig 14)to the opening chamber is considered astandard hookup for all surface drillinginstallations.

This hookup results in the fastest closing time since it requires the least amount of hydraulicfluid to close the BOP.

Fig. 13

Fig. 14


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Looking at Fig 15, the secondary chamber isconnected to the closing chamber resulting inthis optional control technique.

This hookup reduces the closing pressure needed to close the BOP to approximately 67%of the pressure required by the standardhookup.

However, this hookup requires more fluidvolume to close and thus results in a slowerclosing time compared to the standard hookup.

When operating most annular BOPs on theseabed in a subsea operation thehydrostatic pressure of the drilling fluidcolumn in the marine riser exerts anopening force on the BOP.

Since the hydrostatic head of the drillingfluid in the marine riser vary with differentdrilling fluid densities and also with thedepth those BOPs require a differenthydraulic closing pressure, which vary withthose conditions.

The GL BOP’s secondary chamber shouldbe hooked up using one of two techniquesto take the full benefits of the GL’s design.

Subsea Hook-up for water depth up to 800 ft:

Secondary Chamber - Opening Chamber. This control technique requires the same fluidvolume for closing the BOP as the counter balance connection. It is standard hook-up inwater depths up to about 800 ft. Closing pressure requires an adjustment for drilling fluidhydrostatic pressure in the marine riser to account for the opening force exerted on theBOPs piston.

The operators manual should be consulted for adjusting the correct hydraulic controlpressures.

Fig. 15

Fig. 16


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Subsea Hook-up for water depth over 800 ft:

Secondary Chamber - Closing Chamber. Thiscontrol technique reduces closing pressure byapproximately 33% versus the secondarychamber to opening chamber hook-up. See Fig17. This hoop-up should be considered for usein water depths over 800 ft.

The operators manual should be consulted foradjusting the correct hydraulic controlpressures.

Secondary Chamber - Balance Chamber.

With this control technique the varyinghydrostatic pressures in the marine risercaused by changes of drilling fluid density or

due to varying water depths of the BOP aredirectly compensated for. See Fig 18.

This is obtained by directing the effectiveopening pressure to act also for the closing

of the BOP. The two forces are equal and they counterbalance each other.

The operators manual should be consulted for adjusting the correct hydraulic controlpressures.

Hydril GX annul ar preventer (Fig 19)The Hydril “GX” offers extra performanceand serviceability while retaining the fieldproven features of Hydril annular BOP’s.

The “GX” will close on virtually any drillstem member and seal off the open bore.This feature is called CSO (complete shutoff).

Operating volumes are lower, resulting infaster closing times and smalleraccumulator requirements.No secondary chamber.Latched head design. Fig 19

Fig. 18

Fig. 17


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Opening chamber head separates sealing element from the hydraulic opening chamber.Reduce closing pressure proportionally as well pressure is increased.

Hydril GX annular preventer closing chart.

Fig 14 shows the relationship of closing pressure and well bore pressure for minimum sealoff for GX 18-3/4” –10.000 psi annular preventer. Closing pressures are average and willvary slightly with each packing unit. Use closing pressure shown at initial closure toestablish seal off, and reduce closing pressure proportionally as well pressure isincreased. Well pressure will maintain closure after exceeding the required level. See Fig20.

Fig 20

200

400

600

800

10001200

1400

1600

1800

2000

2200

2400

2600

28003000

0 1000 2000 3000 4000 5000 6000 7000 8000

WELL PRESSURE

C L O S I N G

P R E S S U R E

CSO

3-1/2” Ø

5” Ø7” Ø9-5/8” Ø

13-5/8” Ø


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04.06 Shaffer annular preventers

Wedge cover spherical BOP (Fig 21)Spherical contour of the sealing elementgives a long lasting element life.Element able to close on open hole(CSO).Small amount of seals and components.

Adapter ring separates the wellborepressure from the hydraulic area.

The preventer is balanced - wellborepressure does not assist the preventer toremain closed. Hydraulic pressure must

be maintained on the closing chamber toforce the preventer to seal.

Fig 21

Bol ted cover spherical BOP (Fig 22)Spherical contour of the sealing elementgives a long lasting element life.Element is able to close on open hole(CSO).

Contains few seals and components. Adapter ring separates the wellborepressure from the hydraulic area.

The preventer is balanced - that iswellbore pressure does not assist thepreventer to remain closed. Hydraulicpressure must be maintained on theclosing chamber to force the preventer toseal.

Fig 22


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As the preventer is balanced, it require 1500 psi closing pressure for all size pipe smallerthan 7” and reduced pressure for pipe larger than 7”. See Fig 23.

Fig 23

For stripping operation the size of the pipe being stripped into the well bore and the wellbore pressure have to taking into consideration. See Fig24.

Fig 24


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04.07 Cameron annular preventer

Cameron Cooper type “ D” and “ DL” (Fig 25)In the unique design of the Cameron “DL” annular preventer, closing pressure forces theoperating piston and pusher plate upward to displace the solid elastomer donut and forcethe packer to close inward. As the packer closes, steel reinforcing inserts rotate inwards toform a continuous support ring of steel at the top and bottom of the packer. The insertsremain in contact with each other whether the packer is open, closed on pipe or closed onopen hole.

• Replaceable liners around operating piston.• Weep hole between the wellbore pressure seals and the hydraulic system seals.• A two piece packer. See Fig 26• Operates at higher pressures than most other annular BOP’s.• The preventer is balanced - that is wellbore pressure does not assist the preventer

closed. Hydraulic pressure must be maintained on the closing chamber to force thepreventer to seal.

Fig 25

Fig 26


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The graph in Fig 27 allow determination ofthe approximate closing pressure requiredto seal a given well bore pressure whenstripping into the well.

As a new packer wears during stripping,sealing is improved and the closingpressure required to seal on pipe willdecrease. For this reason, closingpressure should be reduced as often as isnecessary to maintain slight leakage forlubrication of the packer.

Fig 2704.08 Packing unit

Packing units for the annular BOP’s are available in NITRILE, NEOPRENE or NATURALrubber. See Fig 28

NITRILE rubber is for use with oil base or oil additive drilling fluids, provides the bestoverall service life when operated at temperatures between + 20 deg F to + 190 deg F.

NEOPRENE rubber is for low temperature operating service and oil base drilling fluids. Itcan be used at operating temperatures between - 30 deg F to + 170 deg F.

NATURAL rubber is for use in non-oil base drilling fluids and can be used at operatingtemperatures between - 30 deg F to + 225 deg F.

In extreme emergencies and when noother alternatives are available sealingelements can be replaced while drill pipeis in the hole.However, this potentially hazardousprocedure involves a high degree of riskunacceptable in any circumstances otherthan emergency.

The packing units consist of twocomponents as steel segments and rubbercompound.

The steel segments are moulded into the rubber and will partially close over the rubber toprevent excessive extrusion when sealing under high pressure.

The segment will ensure the element maintains it shape. When the element is closed thesteel segment will compress the rubber out against the well bore and create a seal. Whenthe element is opened up the compressed rubber will expand and bring the element to fullopen position again within 30 min.

WELL B ORE PRESSURE

C L O S I N G

P R E S S U R E

Fig 28


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Section 05 Ram preventers

05.00 General

In the industry to-day we are normally taking about four different manufactures of RamPreventers used both for Sub-Sea or Surface application:

Cameron Cooper: Type “U”Type “U-II”Model “T”

Hydril: Hydril Ram Preventer

Shaffer: Model “SL”

Model “LWS”

Koomey: J-line

Visual Inspection: After each well open the Ram Bonnets (doors). The ram cavity and ram block should becleaned prior to the following visual inspection. This visual examination is generic and validfor all ram preventers. A few additional areas are required when inspecting the Cameronor Koomey “J” line ram preventer.

Ram packers.

Ram packers and top seals should be in good condition. Rubber should not be missingfrom the pipe contact area on the front packer or sheared off on the top seal

Bonnet seals.Bonnet seals are generally replaced each time the bonnets are opened.

Top seals.When top seals are not proud above ram block, in order of .075” to .140” for manufacturesin general, the low pressure integrity of the preventer is jeopardized.

Ram cavit y.Visually inspect cavity upper seal seat for damage. The surface finish at the top of thecavity is the most critical aspect of this inspection. Sharp scratches make it difficult for topseal rubber to flow into these grooves for pressure integrity.

Ram blocks.If rams are to be used for hanging off the string, record the part number of the ram blocksand verify their capabilities for hanging off. Tagging (hitting) the rams with drill string is theusual cause of damage to the top of a ram block.

Connecting rods/ram shaft packing.To visually examine the connecting rod, the operating piston must be stroked to the closedposition when the bonnets or doors are open.


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Power ram change piston.Cameron and Koomey rams use PRC pistons to open and close the bonnets. The surfacefinish of these chrome rods should also be checked to assure that the operating systemhas good pressure integrity.

Packing injection.Check to ensure that secondary packing has not been energized. Check weep hole toensure it is free of sealant. Sealant could prevent a primary wellbore seal from leakingduring a stump test which is performed to find such leaks.

Through bore.Visually inspect through bore for key seating record. Repairs should be initiated when thisbore wear exceeds 3/16”.

05.01 Testing

Hang-off test (API Spec. 16A 4.7.2.5)This test shal determine the ability of the ram assembly to maintain a 200-300 psi and fullrated working pressure seal while supporting drill pipe loads. This test shall apply to 11inch and larger blowout preventers. Any hang-off test performed with a variable bore ramshall use drill pipe diameter sizes of the minimum and the maximum diameter designed forthat ram. Documentation shall include:

• Nondestructive examination (NDE) of ram blocks in accordance with manufacturerswritten procedure.

• Load at which leaks develop or 600.000 lb for 5 inch and larger pipe, or 425.000 lbfor pipe smaller than 5 inch, whichever is less.

Note: For variable rams always check with manufacturer for correct value.

Funct ion tests (API RP53 17.3.1) All operational components of the BOP equipment systems should be functioned at leastonce a week to verify the component's intended operations. Function tests may or maynot include pressure tests.

Function tests should be alternated from the driller's panel and from mini-remote panels, ifon location.

Pressure t ests (API RP53 17.3.2)17.3.2.1 All blowout prevention components that may be exposed to well pressureshould be tested first to a low pressure of 200 to 300 psi (1.38 to 2.1 MPa) and then to ahigh pressure.

• When performing the low pressure test, do not apply a higher pressure and bleeddown to the low test pressure. The higher pressure could initiate a seal that maycontinue to seal after the pressure is lowered and therefore misrepresenting a lowpressure condition.

• A stable low test pressure should be maintained for at least 5 minutes.

17.3.2.2 The initial high pressure test on components that could be exposed to wellpressure (BOP stack, choke manifold, and choke/kill lines) should be to the rated workingpressure of the ram BOP’s or to the rated working pressure of the wellhead that the stack


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is installed on, whichever is lower. Initial pressure tests are defined as those tests thatshould be performed on location before the well is spudded or before the equipment is putinto operational service.

There may be instances when the available BOP stack and/or the wellhead have higherworking pressures than are required for the specific wellbore conditions due to equipmentavailability. Special conditions such as these should be covered in the site-specific wellcontrol pressure test program.

17.3.2.3 Subsequent high pressure tests on the well control components should be toa pressure greater than the maximum anticipated surface pressure, but not to exceed theworking pressure of the ram BOP's. The maximum anticipated surface pressure should bedetermined by the operator based on specific anticipated well conditions.

Subsequent pressure tests are tests that should be performed at identified periods duringdrilling and completion activity on a well.

A stable high test pressure should be maintained for at least 5 minutes.

Pressure test operations should be alternately controlled from the various control stations.

17.3.2.4 Initial pressure tests on hydraulic chambers of ram BOP’s and hydraulicallyoperated valves should be to the maximum operating pressure recommended by themanufacturer. The tests should be run on both the opening and the closing chambers.

Pressure should be stabilized for at least 5 minutes.

Subsequent pressure tests are typically performed on hydraulic chambers only betweenwells or when the equipment is reassembled.

Test fluids

17.3.5 Well control equipment should be tested with water. Air should be removedfrom the system before the test pressure is applied. Control systems and hydraulicchambers should be tested using clean control fluids with lubricity and corrosion additivesfor the intended service and operating temperatures.

05.02 Pressure test frequency

Pressure tests on the well control equipment should be conducted at least:

1. Prior to spud or upon installation.2. After the disconnection or repair of any pressure containment seal in the BOP

stack, choke line, or choke manifold, but limited to the affected component.3. Not to exceed 21 days.

05.03 Accumulator response time (API RP53 12.3.3)

Response time between activation and complete operation of a function is based on BOPor valve closure and seal off. For surface installations, the BOP control system should be


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capable of closing each ram BOP within 30 seconds. Response time for choke and killvalves (either open or close) should not exceed the minimum observed ram closeresponse time.Measurement of closing response time begins at pushing the button or turning the controlvalve handle to operate the function and ends when the BOP or valve is closed affecting aseal. A BOP is considered closed when the regulated operating pressure has recovered toits nominal setting. If confirmation of seal off is required, pressure testing below the BOPor across the valve is necessary.

05.04 Cameron ram preventer

Fig 29

Cameron (C.C.C.) manufactures three models of ram preventers specifically designed forsub-sea and surface applications. See Fig 29They are the type “ U” - “U-II” – “ T”.

In all three products the following features are incorporated:

• Power ram change (PRC system).• Four bonnet bolts or studs used per bonnet.• Wedgelock - ram locking system (Optional for type U)• Ram cavities are parallel, top and bottom.• Bonnet and body are forged.

Specific model features:

Type “ U” :• Can be fitted with hydraulic bonnet bolts• Plastic ram shaft packing and weep hole standard

Type “ U-II” :• Hydraulic bonnet studs as standard.• Plastic ram shaft packing and weep hole standard


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Model “T”:• Hydraulic bonnet studs• Replaceable wear pad fitted beneath ram block

In this manual we only look at Cameron type U and U-II

The Cameron “U-II” ram type blow-out preventer includes an internally ported hydraulicbonnet tensioning system, a short stroke bonnet, bore type bonnet seals and the provenadvance of the “U” BOP design. The “U-II” can be provided in single and doubleconfigurations with API flange, hubbed or studded connections, and flanged or hubbedoutlets.

In Fig 30 the single components of a Cameron type U single ram BOP is shown.

Fig 30

A: Bonnet bolt B: Ram change cylinder C: Ram assemblyD: Body E: Bonnet seal F: Ram change pistonG: Locking screw H: Operating cylinder I: Locking screw housingJ: Intermediate flange K: Bonnet L: Operating piston

The short stroke bonnet reduces the opening stroke by about 30%, reduces the length ofthe BOP and reduces the weight supported by the ram change pistons. The bore typebonnet seal fits into a seal counter bore in the body and has a metal anti-extrusion ring.

When talking about Shear rams large bore shear bonnets provides the largest capacityoperating piston to increase shearing force. This means that the operating cylinder isremoved and the piston size increased to obtain higher pressure area.

Due to the shear rams operating piston needs longer travel the intermediate flange isincreased in thickness to facilitate this requirement.

The U and U-II blowout preventers are designed so that hydraulic pressure opens and

closes the rams, and provides the means for quick ram change out. See Fig 31Ram closing pressure, shown in red in Fig 31 closes the rams. When the bonnet bolts areremoved, closing pressure opens the bonnet. When the bonnet has moved to the fully


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1. During pressure test of the ram BOP leakage through the weep hole indicates wornseals against the wellbore and require immediately change out prior to commenceoperation.

2. Leakage during pressure test of the hydraulic chamber indicates worn seal againstthe hydraulic operating side and require immediately change out prior to commenceoperation.

3. The weep hole avoids well bore pressure on the opening side of the hydraulicchamber.

A secondary seal is installed in the top of the intermediate flange. In the event of leakageduring a well control situation the secondary can be engaged by injecting plastic packingthrough a packing ring that will seal against the well bore. See Fig 33.

Fig 33

05.05 Ram locking systems

All ram BOP’s must be equipped with a ram lock system that can either be manualoperated or hydraulic operated to assure that the ram does not open if the hydraulicclosing pressure is lost. If it is a manuel system it should be equipped with extension handwells.


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Wedge Lock (Cameron Iron Works)

The Wedge Lock System (Fig 34) is ahydraulically operated mechanicallocking mechanism, thus demanding aseparate hydraulic system to beactivated and deactivated.The wedgelock system will lock therams in their closed position andmaintain the rams mechanicallyclosed and locked eventhough theactuating pressure is released.The hydraulic operating system canbe interlocked using sequence valves

to ensure that the wedgelock isretracted before pressure is applied toopen the rams.For subsea applications, a pressurebalance chamber is connected to thewedgelock housing to eliminate thepossibility of the wedgelock becomingunlocked due to hydrostatic seawaterpressure.

Poslock (Shaffer)

Shaffer ram BOPsequipped with Poslock (Fig35) pistons are lockedautomatically in the closedposition each time they areclosed. The rams willremain locked in theclosed position even ifclosing pressure isremoved. Hydraulicpressure supplied to theopen side of the pistons isrequired to reopen therams.

The Poslock System utilises locking segments to achieve the positive mechanical lock.The Poslock System has one set of locking segments, which provides for one uniqueposition locking. When the front packer elastomers on the rams become worn the PoslockSystem cannot automatically compensate for increased distance between the mating rampackers. The activation of the Poslock System to lock and to unlock the rams will happenas a result of the mechanical design making the system independent from any additionalhydraulic activating systems.

Fig. 34

Fig. 35


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When closing the rams the hydraulic pressure is applied to the closing side of the pistons.The two complete piston assemblies move towards the well centre until they contact eachother. When the pistons have reached the fully closed position the locking segments havethen reached the position where the larger cylinder liner diameter begins.The closing hydraulic pressure is also exposed to the locking cone, which is a separatepart placed inside the piston. The hydraulic force on the locking cone makes it travel afurther distance towards the well centre inside the piston. This additional travel distanceforces the locking segments to move radial outwards due to the tapered shoulder on thelocking cone. The segments lock the piston in the cylinder liner.

The locking cones maintain the locking segments in position. Springs ensure that thelocking cone position is maintained also if the hydraulic closing pressure is removed.

To open the rams again hydraulic opening pressure is supplied to the pistons opening

side. Initially the locking cone will travel a short distance inside the piston. This allows thelocking segments to retract allowing the piston to open the rams.

UltraLock (Shaffer)

Shaffer ram BOPs that are equippedwith the UltraLock (Fig 36) system arelocked automatically in the closedposition each time the rams areclosed. The rams remain locked in theclosed position also if the hydraulic

closing pressure is removed. Hydraulicopening pressure is required to unlockand re-open the rams.The locking system is mechanical andconsists of spring loaded locking dogsthat are engaged against restrainedlocking rods. Four rods per piston areused with four mating locking dogs.The load is carried simultaneously ona pair of two rods and locking dogswhich are placed 180 degrees apart.This allows a greater number of lockedpositions.

Due to the design no additionalhydraulic lines or functions arerequired for activating and deactivatingof the UltraLock.

Hydraulic pressure is applied to thepistons when closing. The entire piston assembly moves towards the well centre togetherwith the rams. When the rams meet each other the motion becomes restricted. At thisstage the hydraulic pressure forces the secondary piston to move an additional distancewithin the UltraLock piston. This allows the locking segments to move radial outwards. The

Fig. 36


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radial motion supported by springs engages the locking segments into their respectivelocking rods.

The rams will be maintained in the locked position even if the hydraulic pressure is lost orremoved.

The interlock between the locking rods and the locking dogs is obtained by a mating toothprofile machined into the surface of the locking rods and in the locking dogs.

With wear on the front packer elastomers the further motion of the assembly towards thewell centre will make the locking dogs engage at this new position.

The UltraLock adjusts the locking position closer to the well centre along with wear on thefront packer elastomers.

When hydraulic pressure is applied to open the rams, the secondary piston responds atfirst and consequently the locking segments become disengaged. Consequently theUltrLock piston can move unrestricted and open the rams.

UltraLock II (Shaffer)

The Shaffer UltraLock II locking system (Fig 37 & 38) incorporates a mechanical lockingmechanism within the piston assembly.

The locking system is independent of hydraulic closing pressure to remain locked. It usesflat tapered locking segments carried by the operating piston, which engages with anotherstationary and tapered shaft fixed in the operating cylinder. When using SL-D rams, theUltraLock II has hang-off capabilities up to 600,000 pounds at full working pressure.

The system needs no adjustments, no matter the size of the pipe rams. Different size ortype ram assemblies can be freely interchanged.

Fig. 37

Fig. 38


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Only one hydraulic function is required to operate the cylinder’s open/close function andthe locking system. The system automatically locks in the closed position each time thepiston assembly is closed compensating for front packer wear. Once the operating pistonis closed on the pipe, the locks are engaged until opening pressure is applied. Onlyhydraulic pressure can unlock and reopen the rams.

Multiple Position Locking MPL (Hydril)

Some Hydril ram BOPs are available with automatic Multiple Position ram Locking MPL(fig39 & 40). MPL allows the ram to seal off with optimum seal squeeze effect on everyclosure. MPL automatically locks and maintain the rams closed with optimum rubberpressure required for seal off on the front packer and upper seal.

Front packer seal wear (on any ram BOP) requires a different ram locking position closerto the well centre to ensure an effective seal off. MPL is designed to automatically adjust tothe new seal off position.

A mechanical lock is automatically set each time the ram is closed. Ram closure isaccomplished by applying hydraulic pressure to the closing chamber, which moves theram to a seal off position. The locking system maintains the ram mechanically locked whileseal off is retained even after releasing hydraulic closing pressure. The ram is opened onlyby application of hydraulic opening pressure. This releases the locking system initially andthen opens the ram.

Fig. 39

Fig. 40


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Fig 39 shows the ram maintained closed and sealed off by the MPL. Hydraulic closingpressure has been released. The Hydril ram BOP automatically maintains ram closure andseal off. MPL will maintain the required rubber pressure on the front packer and upper sealto ensure a seal off up to the BOP Rated Working Pressure. MPL will maintain the seal offwithout closing pressure and with opening forces created by hanging the drill string on theram.

A unidirectional clutch mechanism and a lock nut control locking and unlocking of the MPL.The unidirectional clutch mechanism maintains the nut and ram in a locked position untilthe clutch is disengaged by application of opening hydraulic pressure.

Hydraulic opening pressure disengages the clutch plates to permit the lock nut to rotatefreely and the ram to open.

The travel of the piston and the threaded tail rod during closing or opening the ram causesthe lock to rotate. The fast lead six-path helical thread rotates the nut three turns per footof travel.

05.06 Cameron ram assembl y

All BOP manufactures supply three different types of rams:

• Fixed ram assemblies.• Variable ram assemblies.• Shear/Blind ram assemblies.

Fixed ram assembly

The ram assembly consist of RamBody, Front Packer and Top Seal. Todress the ram body the front packermust be installed first. The top seal isthen installed and locks the frontpacker in place.See Fig41.

The fixed ram assembly can beobtained in different sizes rangingfrom 2-3/8” to 6-5/8”.

Fig 41

Ram packers and top seals should be in good condition. Rubber should not be missingfrom the pipe contact area on the front packer or sheared off on the top seal. As a generalrule, ram packers should be considered acceptable when 80% of the rubber in the pipecontact area is still in place.


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Variable ram assembly

One set of variable bore rams can beused to seal on a range of pipe. Aset of variable bore rams installed ina BOP saves a round trip of aSubSea BOP stack by eliminatingthe need to change rams whendifferent diameter drill strings are inuse. A set of variable bore rams in aBOP stack provides backup for twoor more sizes of standard pipe ramsor serves as the primary ram for onesize and the backup for the other.

See Fig 42.

Fig 42

Shear/Blind ram assembly

Shear/Blind rams are designed to shear drill pipe and lighter tubular like tubing andestablish a seal against wellbore pressure using high hydraulic closing pressure.

The Shear/Blind rams consist of a

upper and lower ram body. To dressa Shear/Blind ram body (C) the bladeor front packer (F) is installed first.The side packers (B) is then installedto keep the blade packer in placeand finally the top packer (E) isinserted to lock the side packers.See Fig 43.

Fig 43

Importance of ram packer pressure

Packer pressure is the internal elastomer compressive force generated in the ram packerswhen closing hydraulic pressure drives the ram assemblies into contact with each other.For a ram assembly to contain wellbore pressure the packer pressure must be higher thanthe wellbore pressure trying to get past the rubbers. Typically, closing hydraulic operatingpressure generates several thousand psi elastomer pressure inside the ram packers. Thisis sufficient to initially contain wellbore pressure. See Fig 44. As wellbore pressure rises,the packer pressure rises as well due to the closing effect that the wellbore pressure hasupon the ram blocks. See Fig 45.


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With this mechanism, packer pressure is maintained above wellbore pressure.

Fig 44 Fig 45

When we have a worn out ram cavity or worn ram rubbers, the closing operating pressureis not able to generate the required packer pressure with a leak resulting.

Feedable rubber

All major ram type BOP manufacturers use the feedable rubber design concept in theirram packers. This includes Cameron, Hydril, Shaffer and MH Koomey. Extrusion platesmoulded into the front packer serves several purposes:

• To support the rubber to prevent unwanted extrusion due to wellbore forces in thevertical direction.

• Act as pistons to extrude feedable rubber to the point of pipe contact. See Fig 46.

Fig 46

A new front packer contains large volume of feedable rubber. When seal off is obtained, alarge clearance exists between the ram and pipe.

A moderately worn packer still retains a large but reduced volume of feedable rubber. The

clearance between the ram and pipe is reduced at the seal off position.


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The extensively worn front packer has used almost all of the feedable rubber volume, butstill able to effect a full rated seal off. The clearance between the ram and pipe is nowapproaching zero, indicating completion of the useful life of the front packer.

Note: All ram type BOP’s are only designed to contain and seal Rated Working Pressurefrom one direction ie. from below the ram.

05.07 Operating ratio

The first ram preventers used in drilling operations were manually operated. Threadedstems were provided to move ram blocks back and forth between the open and closeposition. It soon became apparent that a faster operating method was needed to close therams when a well kicked. This led to the development of hydraulic operated pistons toclose or open the rams.

In Fig 47 is showed a simplified sketch of a hydraulic operated ram preventer. Fluidoperating on the operating piston closes or opens the rams. Each type and size of rampreventer has a specified closing and opening ratio, which is a function of that ramsparticular geometry.

Fig 47

Closing Ratio.

Definition: A dimensionless factor equal to the wellbore pressure divided by theoperating pressure necessary to close the ram BOP against wellborepressure.

When closing the rams, hydraulic closing pressure acting on the ram operating piston areamust overcome the wellbore pressure acting on the ram shaft area which is attempting toforce the ram in to open position. This ratio exists because of difference in areas that theclosing hydraulic pressure acts upon compared to the ram rod area exposed to wellborepressure. See Fig 48.

RAMPISTON

RAM SHAFT

CLOSING CHAMBER

OPENING CHAMBER


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Closing ratios are generally in therange from 6:1 to 11:1. This meansthat it takes 1 psi of closing hydraulicpressure per 6 to 11 psi wellborepressure to close the preventer.Stated in another way, on apreventer with closing ratio of 6:1, ifthe wellbore pressure is 3000 psi itshould take 500 psi hydraulicpressure to close the preventer.

Fig 48

The extreme case is closing the ram preventer while it is exposed to maximum ratedpressure in the wellbore. This required closing pressure is calculated by the following

formula:

Opening ratio.

Definition: A dimensionless factor equal to the wellbore pressure divided by operatingpressure necessary to open a ram BOP containing wellbore pressure.

OPENING RAMS UNDER PRESSURE IS NOT RECOMMENDED. THE FOLL OWING ARE FOR INFORMATION AND UNDERSTANDING PURPOSES ONLY!

When opening rams, hydraulic opening pressure acting on the ram operating piston areamust overcome the wellbore pressure acting on the back side of the ram blocks. Thiswellbore pressure is holding the rams in the closed position. The area behind the ramblocks is fairly large, so the opening ratios are much lower. Opening ratios between 1:1and 4:1 are common. Some preventers have opening ratios less than 1:1 which meansthat the opening pressure must exceed the wellbore pressure.

In Fig 49 is an exposed viewshowing forces on a ram block andram shaft while containing pressurebelow the ram cavity. The packer issealed on pipe and opening force isbeing applied to the operating piston.

Fig 49

The extreme case is opening the ram preventer while it is exposed to maximum ratedpressure in the wellbore. This required opening pressure is calculated by the followingformula:

WELLPRESSURE

RAM SHAFT AREA

CLOSING AREA

CLOSINGPRESSURE

Closing pressure required to Rated Working Pressureclose ram with rated wellbore = -------------------------------------pressure in the bore Closing Ratio

RAM BLOCKRESULTANT

RAM SHAFTRESULTANT

Opening pressure required to Rated Working Pressureopen rams with rat ed working = -------------------------------------pressure in the wellbore Opening Ratio


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05.08 BOP end and side out let Connections

On all type of BOP’s three different types of connections is used both as end connectionsand side outlet connections. This includes ram preventer, annular preventer, drillingspools, casing spools and hydraulic connectors. The three types are Studded, Clamp Huband flanged connection. See Fig 50 - 52.

Studded Connection

Fig 50

Clamp Hub Connection

Fig 51

Flanged Connection

Fig 52

05.09 API type flanges

Two types of flanges are used in wellcontrol equipment according to API. API Type 6BFlange and API Type 6 BX Flange.

API t ype 6B f lange.

API Type 6B flange is a “low” pressured flange with maximum pressure rating of 5000 psi.

API Type R or RX ring gaskets are used for this type flange and does not allow face toface contact between hubs or flanges, so external loads are transmitted through thesealing surfaces of the ring.


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The flange face might be flat or raised type. See Fig 53.

Fig 53

API type 6 BX flange.

API Type 6 BX flange is a “high” pressure flange with maximum pressure rating of 20000psi. API Type BX ring gaskets are used for this type of flange allowing face to face contactof the flanges. The flange face shall be raised except for studded flanges which may haveflat faces. See Fig 54.

Fig 54

FLANGE SECTIONINTERGRAL FLANGE

TOP VIEW

FLANGE SECTIONINTERGRAL FLANGE

TOP VIEW


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RATED

WORKING PRESSURE

FLANGE SIZE RANGE

TYPE 6 B TYPE 6 BX

200030005000

100001500020000

2-1/16” – 21-1/4”2-1/16” – 20-3/4”

2-1/16” – 11”

26-3/4” – 30”26-3/4” – 30”

13-5/8” – 21-1/4”1-13/16” – 21-1/4”1-13/16” – 18-3/4”1-13/16” – 13-5/8”

Marking

According to API the following marking should be visible on the flanges OD:• Manufacturer’s name and mark• API monogram• Nominel Size (Through bore)• Thread size• End and outlet connection size• Rated working pressure• Ring gasket type and number• Ring gasket material

05.10 Ring joint gaskets and grooves

Introduction

Ring Joint gaskets and grooves are described within API RP 16A and API RP 53.• Ring gaskets have a limited amount of positive interference which assures the

gaskets will be joined into sealing relationship within the flanges grooves.• These gaskets shall not be re-used.

Material

The purchaser can specify one of the four different materials when he produces APIgaskets:

MATERIAL HARDNESSBRINELL

IDENTIFICATIONMARKING

Soft Iron 90 DLow -Carbon Steel 120 S

Type 304 Stainless Steel 160 S 304Type 316 Stainless Steel 140 to 169 S 316

Inconel 625 481 to 560


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API t ype “ R” ri ng jo in t gasket

This type “R” ring joint gasket is not energized by internal pressure. Sealing takes placealong small bands of contact between grooves and the gasket on both the OD and ID ofthe gasket. The gasket may be either octagonal or oval in cross section. The Type “R”design does not allow face to face contact between hubs and flanges, so external loadsare transmitted through the sealing surfaces of the ring.

Vibration and external loads may cause small bands of contact between the ring and thegroove to deform plastically, so that the joint may develop a leak unless the flange boltingis periodically tighten. Standard procedure with type “R” joints in the BOP stack is totighten the flange bolting weekly. See Fig 55 & 57.

Fig 55

API Type “ RX” Pressure-Energ ised Ring Join t Gasket

The “RX” pressure-energised ring joint gasket was developed by CIW and adopted by API.Sealing takes place along small bands of contact between the grooves and the OD of thegasket. The gasket is made slightly larger in diameter than the grooves, and iscompressed slightly to achieve initial sealing as the joint is tightened. The “RX” designdoes not allow face to face contact between hubs and flanges. The gasket has large loadbearing surfaces on it’s inside diameter to transmit external loads without plasticdeformation of the sealing surfaces of the gasket. See Fig 55 & 57.

API Type “ BX” Pressure-Energ ised Ring Join t Gasket

In an effort to develop a more compact flange design for high pressure us the “BX” serieswas developed. By allowing face to face contact of the flanges, ring gasket compressionand elastic deformation could be controlled. This allowed a proportionally smaller gasket tobe used with the effect of reducing bolt and ultimately overall flange size.

Sealing takes place along small bands of contact between the grooves and the OD of thegasket. The gasket is made slightly larger in diameter than the grooves, and iscompressed slightly to achieve initial sealing as the joint is tightened. Although the intent ofthe “BX” design was face to face contact between hubs and flanges, the groove andgasket tolerances which were adopted are such that if the ring dimension is on the highside of the tolerance range and the groove dimension is on the low side of the tolerance

Type R Type RX


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range, face to face contact may be very difficult to achieve. Without face to face contactvibration and external loads can cause plastic deformation of the ring, eventually resultingin leaks.The “BX” gasket frequently is manufactured with axial holes to insure pressure balance,since both the ID and OD of the gasket may contact the grooves. See Fig 56 & 57.

Fig 56

According to API the following marking should be visible on the ring gaskets OD:• Manufacturer’s name and mark• API monogram• Type and Number (Example BX 159)• Ring gasket material (Example S 304)

T y p e B X

Fig 57


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API

Type RX and BX ring-joint gaskets should be used for flanged and hub type blow-outpreventer connections in that they are self-energized type gaskets. API type R ringgaskets are not a self-energized type gasket and are not recommended for use on wellcontrol equipment. RX gaskets are used with API type 6B flanges and 16B hubs and BXgaskets are used with type 6BX flanges and 16BX hubs. Detailed specifications for ring-

joint gaskets are included in API Specification 6A and in API Specification 16A. Gasketmaterials, coatings and platings should be in accordance with API Specification 6A.Identification markings should be in accordance with API Specification 6A and APISpecification 16A.


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Section 06 Choke manifold

06.01 General

The choke manifold consists of high pressure pipe, fittings, flanges, valves, and manualand/or hydraulic operated adjustable chokes. This manifold may bleed off wellborepressure at a controlled rate or may stop fluid flow from the wellbore completely, asrequired. See Fig 58.

Fig 58

06.02 Choke manifold – installation

API RP53 8.2Recommended practices for installation of choke manifolds for surface installationsinclude:

1. Manifold equipment subject to well and/or pump pressure (normally upstream ofand including the chokes) should have a working pressure equal to or greater thanthe rated working pressure of the ram BOPs in use.

2. For working pressures of 3000 psi and above, flanged, welded, clamped or otherend connections in accordance with API 6A, should be employed on componentssubjected to well pressure.

3. The choke manifold should be placed in a readily accessible location, preferablyoutside the rig substructure.

4. Buffer tanks are sometimes installed downstream of the choke assemblies for thepurpose of manifolding the bleed lines together. When buffer tanks are employed,provision should be made to isolate a failure or malfunction.


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5. All choke manifold valves should be full bore. Two valves are recommendedbetween the BOP stack and the choke manifold for installations with rated workingpressures of 5000 psi and above. One of these two valves should be remotelycontrolled. During operations, all valves should be fully opened or fully or fullyclosed.

6. A minimum of one remotely operated choke should be installed on 10000 psi,15000 psi and 20000 psi rated working pressure manifolds.

7. Choke manifold configurations should allow for re-routing of flow (in the event oferoded, plugged, or malfunctioning parts) without interrupting flow control.

8. Considerations should be given to the low temperature properties of the materialsused in installations to be exposed to unusually low temperatures and should beprotected from freezing by heating, draining, filling with appropriate fluid, or otherappropriate means

9. Pressure gauges suitable for operating pressure and drilling fluid service should be

installed so that drill pipe and annulus pressures may be accurately monitored andreadily observed at the station where well control operations are to be conducted.

06.03 Choke lines – installation

API RP53 8.3 The choke line and manifold provide a means of applying back pressure on the formationwhile circulating out a formation fluid influx from the wellbore. The choke line (which con-nects the BOP stack to the choke manifold) and lines downstream of the choke should:

1. Be as straight as possible.

2. Be firmly anchored to prevent excessive whip or vibration.3. Have a bore of sufficient size to prevent excessive erosion or fluid friction4. Minimum recommended size for choke lines is 2” nominal diameter for 3K and 5K

arrangements and 3” nominal diameter for IOK, 15K, and 20K arrangements.5. Minimum recommended nominal inside diameter for lines downstream of the

chokes should be equal to or greater than the nominal connection size of thechokes.

6. Lines downstream of the choke manifold are not normally required to containpressure.

7. The bleed line (the line that bypasses the chokes) should be at least equal indiameter to the choke line. This line allows circulation of the well with the preventerclosed while maintaining a minimum back pressure. It also permits high volumebleed off of well fluids to relieve casing pressure with the preventer closed.

06.04 Kil l lines – ins tallation

Kill lines are an integral part of the surface equipment required for drilling well control. Thekill line system provides a means of pumping into the wellbore when the normal method ofcirculating down through the kelly or drill pipe cannot be employed. The kill line connectsthe drilling fluid pumps to a side outlet on the BOP stack. The location of the kill lineconnection to the stack depends on the particular configuration of BOPs and spoolsemployed. The connection should be below the ram type BOP most likely to be closed.

On selective high-pressure, critical wells a remote kill line is commonly employed to permituse of an auxiliary high pressure pump if the rig pumps become inoperative or


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location such items as standpipe pressure, casing pressure, pump strokes, etc., greatlyincreases well control efficiency.

Rig air systems should be checked to assure their adequacy to provide the necessarypressure and volume requirements for controls and chokes. The remotely operated chokeshould be equipped with an emergency backup system such as a manual pump ornitrogen for use in the event rig air becomes unavailable.

Fig 61

Cameron hydraulically actuated drilling choke are available in working pressures from5.000 psi to 20.000 psi. See Fig 61.Cylindrical gate and large body cavity provide high flow capacity. Gate and seat areconstructed of erosion resistant tungsten carbide and are reversible for double life.

An air operated hydraulic pump in the control console ensures positive action gatemovement. Hydraulic pressure of 300 psi applied to the actuator results in an opening orclosing force of 21500 lbs at the gate.

Fig 62

Cameron manually actuated choke are available in working pressures from 5000 psi to20000 psi See Fig 62.

Thrust bearings in the actuator provide low torque handwheel operation. Upstreampressure has no thrust loading on the actuator; only downstream pressure affects thetorque.Like the Auto choke, the cylindrical gate and large body cavity provide high flow capacity.Gate and seat are constructed of erosion resistant tungsten carbide and are reversible fordouble life.

Hydraulic actuator

Position indicator


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The manually operated choke is normally used as a back up in case of problems with thehydraulically operated choke and during special well control operations such as strippingand volumetric well control.

06.07 Hydrates

Hydrates are ice-like solids which are formed when gases are flowing in the presence ofsmall quantities of water vapour.

The temperatures at which hydrates can form may be well above the temperature at whichpure ice would normally be formed, particularly at pressures above atmospheric.

Hydrates form as small lattices of water with interstices which contain gases. The waterforms an ice with molecules of gas locked into the frozen solid lattice. Those can build up

into large pieces of solid hydrate at bends or restrictions, such as chokes or other valves.See Fig 63.

GAS + WATER (VAPOUR)

SOLID HYDRATE BUILD-UP

Fig 63

When hydrates form, the gas becomes "locked" into the solid at the local pressure. It isestimated that 1 cu ft of hydrate may hold the equivalent of 170 standard cubic feetcompressed gas. This can be released when the hydrate is melted by the application ofheat. Once hydrates have formed they may lead to complete plugging of chokes, fail-safevalves, choke lines and expansion points at entry to the mud gas separator. It is normal totry to prevent hydrates from forming by the injection of a suppressant at the upstream sideof the choke or at the BOP, on the occasions when hydrate formation is likely.

Prevention of hydrate formation is always regarded as the preferential action.Monoethylene glycol is the most common suppressant and it has a freezing point of 8.6 ° F(-13 ° C). It should be noted that it is the water-vapour associated with the gas which has tobe inhibited, rather than the whole volume of water in the mud.

It is common in HPHT wells to make provision for the injection of glycol hydratesuppressant at a point into the BOP upstream of the inner choke line valves and upstreamof the choke at the choke manifold. This is done by a glycol injection pump which candeliver at a pressure up to the rated pressure of the choke manifold. The injection isstarted at a point when the gas influx is some depth below the BOP, such as 1500 to 2000ft. The minimum injection rate is about 0.5 gpm but should be increased as necessary.During severe problems with hydrates methanol might be injected as it has a lower

freezing point than glycol.


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06.08 Mud/gas separator

The mud/gas separator is the primary means ofremoving gas from the drilling fluid. There areseveral advantages to removing a largepercentage of the gas from the drilling fluidsbefore the drilling fluid flows to the degasser tankat the s

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