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MAERSK TRAINING CENTRE A/SDOCUMENT ID

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Well Control Equipment Training ManualPREPARED BY

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MAERSK TRAINING CENTRE

DRILLING SECTION

Copyright © Maersk Training Centre a/s.

All rights reserved. No part of this publication may be reproduced, stored in or introducedinto a retrieval system, or transmitted, in any form, or by any means (electronic,

mechanical, photocopying, recording or otherwise) without the prior written permission ofMaersk Training Centre a/s.

WELL CONTROLEQUIPMENT

TRAINING MANUAL


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Well Control Philosophy

It is the philosophy that during the drilling, - testing, completion water injection andwork-over of an oil or gas well, any work undertaken should be executed in such amanner that:

1. Loss of human life and injury to crew members shall be avoided.2. Pollution of the surrounding environment shall be avoided.3. Loss of rig and damage to equipment shall be avoided.

If all of the aforementioned conditions are fulfilled then the economic and ecologicalresult shall be successful.

It is also the philosophy :1. That detection and controlling a kick takes a team effort from all members

of the rig crew. Each member must be completely familiar with his duties sothat any well control operation can proceed smoothly and efficiently.

2. To maintain all well control equipment in first class condition and ready foruse whenever required.

3. To ensure that all personnel directly involved in a well control situation shallbe educated to a standard that ensures complete understanding of anysituation that may arise.

In implementing this philosophy Maersk Contractors’ Drilling Division shall comply withrelevant government legislation and as a prudent safety conscious contractor promote thewelfare of all personnel along with protection of the environment.

Well Control Policies

Maersk Contractors’ Drilling Division requires, as a stated policy, the holding of apre-spud meeting prior to each well or other major offshore activity. At these meetings,the methods of handling various routine and non-routine operations can be covered byall parties concerned, and mutually acceptable methods worked out. Maersk Contractors’ Drilling Division has compiled a ”Well Control Manual”, that willgovern in the absence of any other acceptable set of procedures and guidelines.By setting out our preferred Well Control procedures and guidelines, is not intending tosuggest that the procedures used by others are not equally or perhaps more valid.Only discussion of each situation can resolve that issue.However, for any other Well Control procedures and guidelines to take precedenceover the ones shown in the ”Well Control Manual”, the modified set must becommunicated in writing to the Management of the rig. In the absence of such officialnotice, the Maersk Contractors Drilling Division’s personnel shall be required tofollow the ”Well Control Manual”.

The basic of this well control manual is found according to recommendation in API16E and API²RP 53. Well control equipment and control system according to API³RP53 and API (spec) 16a.


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Table of content:

01 Well control barrier Page 00601.01 Primary well control barrier02.01 Secondary well control barrier

02 BOP Configuration Page 00701.02 Bop stack arrangements02.02 Stack Components codes03.02 Drilling spool

03 Diverter systems Page 01001.03 Purpose of diverter system02.03 Diverter equipment03.03 Guidelines for diverting with string on bottom04.03 Guidelines for diverting with string off bottom05.03 Rotating head06.03 Diverter control system

04 Annular Preventer Page 01601.04 General02.04 Testing03.04 Pressure test frequency04.04 Response time05.04 Hydril annular preventers06.04 Shaffer annular preventers07.04 Cameron annular preventers08.04 Packing unit

05 Cameron Ram Preventer Page 02601.05 General02.05 Testing03.05 Pressure test frequency04.05 Response time05.05 Cameron Ram Preventer06.05 Cameron Ram Assembly07.05 Operating Ratio08.05 BOP and side outlet connections09.05 API type flanges10.05 Ring joint gaskets and grooves

06 Choke Manifold Page 04301.06 General02.06 Choke Manifold - Installation03.06 Choke Lines - Installation04.06 Kill Lines - Installation05.06 HCR – Side Outlet Valves06.06 Chokes


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07.06 Hydrates08.06 Mud/Gas Separator09.06 Degasser

07 Control System Page 05101.07 General02.07 Response Time03.07 Storage Equipment04.07 Pump Requirements05.07 Accumulator Bottles and Manifolds06.07 Hydraulic Control Manifold07.07 Schematic of Control System08.07 Remote Control Panel09.07 Accumulator Volumetric Requirements

08 Auxiliary Equipment Page 06101.08 Kelly Valves02.08 Top Drive Valves03.08 Drillpipe Safety Valve 04.08 Inside Blowout Preventer05.08 Drillstring Float Valve06.08 Test Plug07.08 Cup Type Tester08.08 Triptank09.08 Pit Volume Measuring Devices10.08 Flow Rate Sensor

09 Recommended Pressure Test Practices Page 06601.09 Initial Test02.09 Subsequent Test


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Abbreviations:

A Annular preventerAPI American Petroleum InstituteBOP Blow-out PreventerC Hydraulic connectorCSO Complete shut offF FarentheitFOSV Full Opening Safety ValveG Rotating headGAL GallonsK Pressure 1.000 psiHCR High Closing RatioH2S Hydrogen sulfideIBOP Inside Blow-out PreventerID Internal diameterLBS PoundMGS Mud/Gas SeparatorOD Outside diameterP PressurePRC Power ram changePSI Pound per inch²R Ram preventer (single)Rd Ram preventer (double)Rt Ram preventer (tripple)RP Recommended PracticeS Drilling spoolSCF Standard Cubic FeetV Volume


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01 Well control barrier.

01.01 Primary well control barrier.

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.

02.01 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 andformation 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 tocompany 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:

FOSV (full opening safety valve)One way valves (IBOP, Dart sub)Check valves (Drill pipe floats)

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

Annular PreventerRam PreventerShear/Blind RamRotating head

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


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02 BOP Configuration

01.02 Bop stack arrangements

Example arrangements for BOP equipment are based on rated working pressures.Example stack arrangements shown in Figures 1 and 2 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 Working Pressure

2K 2,000 psi (13.8 MPa)3K 3,000 psi (20.7 MPa)5K 5,000 psi (34.5 MPa)

IOK 10,000 psi (69.0 MPa) 15K 15,000 psi (103.5 MPa) 20K 20,000 psi (138.0 MPa)

Fig 01

02.02 Stack Component Codes

Every installed ram BOP should have, as a mmaximum anticipated surface pressure to be ecodes for designation of BOP stack arrangeme

G = Rotating head.

A = Annular type BOP.

R = Single ram type BOP with one set ofprefers.

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Fig 02

inimum, a working pressure equal to thencountered. The recommended componentnt are as follows:

rams, either blank or for pipe, as operator


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

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 equal tothe BOP stack rated working pressure.

K = 1 000 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, would have athroughbore of 13-5/8” (34.61 cm), and would be arranged as in Figure 2b.

Annular BOP’s may have a lower rated working pressure than the ram BOPS.

03.02 Drilling Spool

Choke and kill lines may be connected either to side outlets of the BOP’s, 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

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Drilling spools for BOP stacks should meet the following minimum qualifications:

a. 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, and

20K 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, or

hubbed.

b. Have a vertical bore diameter the same internal diameter as the mating BOP’s and atleast equal to the maximum bore of the uppermost casing/tubing head.

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

For drilling operations, wellhead outlets should not be employed forchoke or kill lines.


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0 Diverter Systems

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Fig 04

1.03 Purpose of Diverter system

diverter system is often used during top-hole n or halt flow, but rather permits routing of thsed to protect the personnel and equipment bellbore fluids emanating from the well to a sahe system deals with the potentially hazardouetting the casing string on which the BOP stackystem is designed to pack-off around the Kellafe direction. Diverters having annular packingole. Valves in the system direct the well flow wf the valves may be tegral to the diverter unit.

2.03 Diverter equipment

he diverter system consists of a low pressufficient internal bore to pass the bit requireddequate size [6 inches (15.24 cm) or larger] arextended to a location(s) sufficiently distant from

onventional annular BOP’s See Fig 05, inseeads See Fig 10 can be used as diverters. Tnd vent line(s) are designed and sized to permellbore back pressure. Vent lines are typicaffshore and 6 inches (15.24 cm) or larger ID for

drilling. A diverter is not designed to shute flow away from the rig. The diverter isy re-routing the flow of shallow gas and

fe distance away from the rig. See Fig 04s flows that can be experienced prior to and choke manifold will be installed. They, drill string, or casing to divert flow in a units can also close on wire line and openhen the diverter is actuated. The function

in

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ure diverter or an annular preventer of for subsequent drilling. Vent line(s) of attached to outlets below the diverter and the well to permit safe venting.

rt-type diverters See Fig 06, or rotatinghe rated working pressure of the diverterit diverting of well fluids while minimizinglly 10 inches (25.4 cm) or larger ID for

onshore operations.


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Fig 05

If the diverter sopening and installed). Thevalve is in theseparate operbeen changed

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Fig 06

ystem incorporates a valve(s) on the vent line(s), this valve(s) should be fullfull bore (have at least the same opening as the line in which they are system should be hydraulically controlled such that at least one vent line

open position before the diverter packer closes. The older systems haveating handles for each components as seen in Fig 07, but most have now so the valves is integral to the diverter unit.

ig 07


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

a. Open B or C depending on wind directionb. Close Ec. Close A

In modern systems the diverter is integral to an annular preventer and is only equippedwith one diverter line witch is diverted into two lines by a Selector valve that makes itpossible to divert fluid and gas to either side of the rig depending of wind direction or toboth side at the same time. See Fig 08

Fig 08

The diverter and all valves should be functimes during operations to determine that the

CAUSION: Fluid should be pumped througappropriate times during operations to asceclean-out ports should be provided at all lotracings may he required in colder climates.

The hydraulic supply pressure to the divehydraulic control unit with 3.000 psi.

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tion tested when installed and at appropriate system will function properly.

h the diverter and each diverter vent line atrtain the line(s) is not plugged. Inspection andw points in the system. Drains and/or heat

rter control panel is routed directly from the


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03.03 Guidelines for diverting with string on bottom

1. Route returns to downwind vent line and close diverter

2. Pump at maximum rate and switch to kill fluid without shutting down pumps.If no kill fluid use sea water. (Do not shut down the pumps)

3. If diverter system fails before control of the well is regained or broaching tosurface occurs, evacuate all personnel, leaving the mud pumps running onsea water at maximum rate.

04.03 Guidelines for diverting with string off bottom

If it becomes necessary to divert gas, water and/or sand debris, route returns to downwindvent line and close diverter.

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

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

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

05.03 Rotating HeadFig 09

Rotating control heads or rotating blow-outpreventers are not a new concept. Therotating head maintains a constant sealaround all of the rotating elements in thedrill string except such large diameterpieces as the bit and reamer. This seal ismaintained when going in, coming out orholding in static position. The originalequipment was designed for air drillingand later used for mud, gas andgeothermal applications. Later generationequipment was applied by industry for theflow drilling applications that cause highpressures at the wellhead. The originaldesign and engineering principals for itsuse have held and still apply today. Withinthe BOP system the API recognizes therotating head as a diverter. See Fig 09.The rotating BOP is always used on top of a regular BOP stack consisting of ram andannular BOP’s.


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The rotating head seals off around almost any shape of Kelly and will also seal on anytype of drill pipe whether flush joint, upset or coupled. No special operations are requiredfor handling the pipe. As the various elements of the drill string are raised or lowered, the“stripper rubber” changes shape to conform to the OD of these elements. In this way thehole is closed at all times. A flanged out let below the stripper rubber allows pressure to bedirected out through the flow line.

The rotating blow-out preventer is ideal for use wherever there is:

Drilling where H2S is encounted.

Circulating with air or gas.

Under balanced drilling.

Drilling with reverse circulation.

Drilling in areas susceptible to blow-outs.

Geothermal drilling.

The rotating blow-out preventer consists of three major assemblies. See Fig 10.

The rotating assemblyThe Body

Kelly drive unitFig 10

The body is flanged to the top of the blow-outpreventer and the rotating assembly is lockedin with a quick release mechanism. The kellydrive unit is installed on the kelly and turns therotating sleeve that has the stripper rubberattached to the lower end. The stripper rubberseals off the well pressure between theannulus of the hole and the outside of the drillpipe. The rotating sleeve packing effectivelyseals between the outside of the rotatingsleeve and rotating assembly housing.

The stripper rubber is constructed in suchmanner that as the well pressure increases,the stripper forms a tighter seal. Some rotatingheads is build with hydraulic pressurizesstripping rubbers.

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, reduce


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differential sticking and hole drag caused by mud cake, and reduce trouble time duringdrilling. Because underbalanced drilling creates the condition for fluid to flow from theformation into the well bore, successful underbalanced drilling must include the selectionof proper control equipment to handle the drilling fluids and formations fluid. The rotatingcontrol head is one of the major elements of the system.

06.03 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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04 Annular Preventers

01.04 General

In the industry to-day we are normally taking about three different manufactures of AnnularPreventers used both for SubSea or Surface application:

Cameron Cooper:Type “D”Type “DL”

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

Shaffer:Shaffer Spherical.

Visual Inspection:

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.

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.


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02.04 Testing

Function test:All operational components of the BOP equipment systems should be functioned atleast once a week to verify the component's intended operations. Function testsmay or may not include pressure tests.

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

Pressure test:All blowout prevention components that may be exposed to well pressure should betested first to a low pressure of 200 to 300 psi (1.38 to 2.1 MPa) and then to a highpressure.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 on components that could be exposed to well pressure(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 thestack is installed on, whichever is lo er. Initial pressure tests are defined as thosetests that should be performed on lo ation before the well is spudded or before theequipment is put into operational seAnnular BOPS, with a joint of drill piapplied to the ram BOP’s or to a mworking pressure, whichever is the l

Subsequent high pressure tests on should be tested to a minimum of 70pressure of the ram BOP’s, whichevthat should be performed at identifieon a well.A stable high test pressure shouldlarger size annular BOPs some smarubber mass for prolonged periodsmovement should be considered whPressure test operations should bestations.

The pressure test performed on hyto at least 1,500 psi (10.3 MPa). The tests should be run on both the Pressure should be stabilized for at

Subsequent pressure tests are typbetween wells or when the equipme

wc

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rvice.pe installed, may be tested to the test pressureinimum of 70 percent of the annular preventeresser.

annular BOP’s, with a joint of drill pipe installed, percent of their working pressure or to the tester is less. Subsequent pressure tests are testsd periods during drilling and completion activity

be maintained for at least 5 minutes. Withll movement typically continues within the large

after pressure is applied. This packer creepen monitoring the pressure test of the annular. alternately controlled from the various control

draulic chambers of annular BOP’s should be

opening and the closing chambers.least 5 minutes.

ically performed on hydraulic chambers onlynt is reassembled.


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03.04 Pressure test frequency

Pressure tests on the well control equipmen

a. Prior to spud or upon installatio

b. After the disconnection or repBOP stack, choke line, or component.

c. Not to exceed 21 days.

04.04 Response time

Response time between activation and comor valve closure and seal off. Closing timepreventers smaller than 18-3/4” nominal bo18-3/4” and larger. Measurement of closingturning the control valve handle to operate thclosed effecting a seal. A BOP may be copressure has recovered to its nominal setting

05.04 Hydril annular preventer

Hydr GK annular preventerSee Fig 11

The “GK” annular blow-out preventerwas designed especially for surfaceinstallations and is also used on offshoreplatforms and sub-sea. The “GK” is auniversal annular blow-out preventer witha long record of proven 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 bothopening and closing pressure. Seal off iseffected by hydraulic pressure applied tothe closing chamber which raises thepiston, forcing the packing unit into asealing engagement.The “GK” is designed to be well pressure asinitial seal off has been effected. As wemaintained by well pressure alone.

t should be conducted at least:

n.

air of any pressure containment seal in thechoke manifold, but limited to the affected

plete operation of a function is based on BOP should not exceed 30 seconds for annularre and 45 seconds for annular preventers of response time begins at pushing the button ore function and ends when the BOP or valve is

nsidered closed when the regulated operating.

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sisted in maintaining packing unit seal off oncell bore pressure further increase closure is

Fig 11


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Hydril GL annular preventerSee Fig 12

Hydril “GL” annular preventer aredesigned and developed both for subseaand surface operations. The provenpacking unit provides full closure atmaximum working pressure on open holeand vitually anything in the bore - casing,drill pipe, tool joints, Kelly or tubing.Screwed or latched head are available.Opening chamber head separatessealing element from hydraulic openingchamber.Closing pressure depends upon themanner in which the secondary port isconnected into the hydraulic operatingsystem.T e secondary chamber, which is unique to the “GL” BOP, provides this unit with greatfi

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Fig 12

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lexibility of control hook-up and acts as backup closing chamber to cut operation cost andncrease safety factors in critical situations.

Hydril GX annular preventerSee Fig 13

he Hydril “GX” offers extra performance and serviceability while retaining the field proveneatures of Hydril annular BOP’s.he “GX” will close on vitually any drill stem member and seal off the open bore.

Fig 13


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This feature is called CSO (complete shut off).Operating volumes are lower, resulting in faster closing times and smaller accumulatorrequirements.No secondary chamber.Latched head design.Opening chamber head separates sealing element from the hydraulic opening chamber.Reduce closing pressure proportionally as well

Hydril GX annular preventer closing c

Fig 14 shows the relationship of closing pressuoff for GX 18-3/4” –10.000 psi annular prevenvary slightly with each packing unit. Use cloestablish seal off, and reduce closing preincreased. Well pressure will maintain closure 14.

Fig 14

200

400

600

800

1000

1200

1400

1600

1800

2000

2200

2400

2600

2800

3000

0 1000 2000 3000 4WEL

CLO

SIN

G P

RES

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E

9-5/8” Ø

13-5/8” Ø

pressure is increased.

hart

re and well bore pressure for minimum sealter. Closing pressures are average and willsing pressure shown at initial closure to

ssure proportionally as well pressure isafter exceeding the required level. See Fig

CSO

© MTC

000 5000 6000 7000 8000L PRESSURE

3-1/2” Ø

5” Ø7” Ø


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06.04 Shaffer annular preventer

Wed e cover spherical BOPSee Fig 15

Spherical cgives a longElement ab(CSO).Small numbAdapter rinpressure froThe prevewellbore prpreventer tpressure mclosing chaseal.

Bolte

Spherical cgives a longElement ab(CSO).Small numbAdapter rinpressure froThe prevewellbore prpreventer tpressure mclosing chaseal.

As the prevthan 7” and

g

ection 2.doc © MTC

ontour of the sealing element lasting element life.le to close on open hole

ers of seal and components.g separates the wellborem the hydraulic area.

nter is balanced - that isessure does not assist theo remain closed. Hydraulicust be maintained on the

mber to force the preventer to

Fig 15

d cover spherical BOPSee Fig 16

ontour of the sealing element lasting element life.le to close on open hole

ers of seal and components.g separates the wellborem the hydraulic area.

nter is balanced - that isessure does not assist theo remain closed. Hydraulicust be maintained on the

mber to force the preventer to

Fig 16

enter is balanced it require 1500 psi closing pressure for all size pipe smaller reduced pressure for pipe larger than 7”. See Fig 17.


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For stripping operation the size of the pipe being stripped into the well bore and the wellbore pressure have to taking into consideration. See Fig 17.

07

Inopthfo

WCF Surface\3\1\Section 2.doc

Fig 17

.04 Cameron annula

Type “D” and “D

the unique design oferating piston and pu

e packer to close inwarm a continuous supp

© MTC

r preventer

L”See Fig 18

the Cameron “DL” annular preventer, closing pressure forces thesher plate upward to displace the solid elastomer donut and forcerd. As the packer closes, steel reinforcing inserts rotate inwards toort ring of steel at the top and bottom of the packer. The inserts


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remain in contact with each other whether the acker is open, closed on pipe or closed onopen hole.Replaceable liners around operating piston.Weep hole between the wellbore pressure sealA two piece packer. See Fig 19Operates at higher pressures than most other aThe preventer is balanced - that is wellbore preHydraulic pressure must be maintained on theseal.

Fig 18

p

s and the hydraulic system seals.

nnular BOP’s.ssure does not assist the preventer closed. closing chamber to force the preventer to

© MTC

Fig 19


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The graph in Fig 20 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 20

08.04 Packing unit

Packing units for the annular BOP’s areavailable in NITRILE, NEOPRENE orNATURAL rubber. See Fig 21

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

NEOPRENE rubber is for low temperatureoperating service and oil base drilling fluids.It can be used at operating temperaturesbetween - 30 deg F to + 170 deg F.

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

In extreme emergencies and when no other alternatives are available sealing elementscan be replaced while drill pipe is in the hole.However, this potentially hazardous procedure involves a high degree of risk unacceptablein any circumstances other than emergency.

The packing units consist of two components as steel segments and rubber compound.

WELL BORE PRESSURE

CLO

SIN

G P

RES

SUR

E

Fig 21


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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.


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05 Ram Preventer

01.05 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.

1. Ram Packers, Top Seals and Bonnet Seals

Ram Packers.Ram packers and top seals should be in good condition. Rubber should not bemissing from 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” formanufactures in general, the low pressure integrity of the preventer is jeopardized.

2. Ram CavityVisually inspect cavity upper seal seat for damage. The surface finish at the top ofthe cavity is the most critical aspect of this inspection. Sharp scratches make itdifficult for top seal rubber to flow into these grooves for pressure integrity.

3. Ram BlocksIf rams are to be used for hang off, record the part number of the ram blocks andverify their capabilities. Tagging rams is the usual cause of damage to the top of aram block.


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Hang-Off Test.

According to API 16A the following minimum value is given before leaks develop for fixedpipe rams:

5” fixed rams 600.000 lbs3-1/2” fixed rams 425.000 lbs

For variable rams always check with manufacturer for correct value.

4. Connecting Rods/Ram Shaft PackingTo visually examine the connecting rod, the operating piston must be stroked to theclosed position when the bonnets or doors are open.

5. Power Ram Change PistonCameron and Koomey rams use PRC pistons to open and close the bonnets. Thesurface finish of these chrome rods should also be checked to assure that theoperating system has good pressure integrity.

6. Packing InjectionCheck to ensure that secondary packing has not been energized. Check weep holeto ensure it is free of sealant. Sealant could prevent a primary wellbore seal fromleaking during a stump test which is performed to find such leaks.

7. Through BoreVisually inspect through bore for key seating record. Repairs should be initiatedwhen this bore wear exceeds 3/16”.

02.05 Testing

Function testAll operational components of the BOP equipment systems should be functioned atleast once a week to verify the component's intended operations. Function testsmay or may not include pressure tests.

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

Pressure testAll blowout prevention components that may be exposed to well pressure should betested first to a low pressure of 200 to 300 psi (1.38 to 2.1 MPa) and then to a highpressure.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.


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The initial high pressure test on components that could be exposed to well pressure(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 wellheadthat the stack is installed on, whichever is lower. Initial pressure tests are definedas those tests that should be performed on location before the well is spudded orbefore the equipment is put into operational service.There may be instances when the available BOP stack and/or the wellhead havehigher working pressures than are required for the specific wellbore conditions dueto equipment availability. Special conditions such as these should be covered in

03.05

Pres

04.05

Respor vacapavalverespo

Surface\3\1\Section 2.doc © MTC

the site-specific well control pressure test program.

Subsequent high pressure tests on the well control components should be to apressure greater than the maximum anticipated surface pressure, but not toexceed the working pressure of the ram BOP's. The maximum anticipated surfacepressure should be determined by the operator based on specific anticipated wellconditions.Subsequent pressure tests are tests that should be performed at identified periodsduring drilling 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 controlstations.

Initial pressure tests on hydraulic chambers of ram BOP’s and hydraulicallyoperated valves should be to the maximum operating pressure recommended bythe manufacturer.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 onlybetween wells or when the equipment is reassembled.

Pressure test frequency

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

a. Prior to spud or upon installation.

b. After the disconnection or repair of any pressure containment seal in theBOP stack, choke line, or choke manifold, but limited to the affectedcomponent.

c. Not to exceed 21 days.

Response time

onse time between activation and complete operation of a function is based on BOPlve closure and seal off. For surface installations, the BOP control system should beble of closing each ram BOP within 30 seconds. Response time for choke and kills (either open or close) should not exceed the minimum observed ram closense time. Measurement of closing response time begins at pushing the button or


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turning the control valve handle to operate the function and ends when the BOP or valve isclosed effecting a seal. A BOP may be considered closed when the regulated operatingpressure has recovered to its nominal setting. If confirmation of seal off is required,pressure testing below the BOP or across the valve is necessary.

05.05 Cameron ram preventer

COTsurfaThey

In all

Spec


Fig 22 manufactures three models of ram preventers specifically designed for sub-sea andce applications. See Fig 22 are the type “U” - “U-II” - Model T.

three product the following features are incorporated:

Power ram change, PRC, system.Four bonnet bolts or studs used per bonnet.Using wedgelock.Ram cavities are parallel, top and bottom.Bonnet and body are forged.

ific Model Features:

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

Type “U-II”:Hydraulic bonnet studsPlastic ram shaft packing and weep hole standard

Model “T”:Hydraulic bonnet studsReplaceable wear pad fitted beneath ram block


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M:\IWCF Surface\3\1\Sec

In this manual we only look on Cameron type “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 either API flange, clamp hub or studded connections, and flange orclamp hub outlets.

In Fig 23 the single components of a single ram BOP is showed.

Fig 23

A: Bonne bolt B: Ram Change cylinder C: Ram assemblyD: BodyG: LockinJ: Interm

The short strthe BOP andbonnet seal f

When talkingoperating pisremoved and Due to the sincreased in

The U II blowrams, and prRam closing removed, cloextended poseach ram to lRam openingafter ram ch

t

tion 2.doc © MTC

E: Bonnet seal F: Ram Change pistong screw H: Operating cylinder I: Locking screw housingediate flange K: Bonnet L: Operating piston

oke bonnet reduces the opening stroke by about 30%, reduces the length of reduces the weight supported by the ram change pistons. The bore type

its into a seal counter bore in the body and has a metal anti-extrusion ring.

about Shear rams large bore shear bonnets provides the largest capacityton to increase shearing force. This means that the operating cylinder is the piston size increased to obtain higher pressure area.

hear rams operating piston needs longer travel the intermediate flange isthickness to facilitate this requirement.

out preventer is designed so that hydraulic pressure opens and closes theovides the means for quick ram change out. See Fig 24pressure, shown in red in Fig 24 closes the rams. When the bonnet bolts aresing pressure opens the bonnet. When the bonnet has moved to the fullyition, the ram is clear of the body. An eyebolt can be installed into the top of

ift it out of the preventer. pressure, shown in blue in Fig 24 opens the rams and closes the bonnetsange out. The rams are pulled outward, close to the bonnets before the


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bonnets begin moving toward the preventer body. This assures that the rams neverobstruct the bore or interfere with pipe in the hole. Hydraulic pressure draws the bonnetstightly against the preventer body and the bonnet bolts are reinstalled to hold the bonnetsclosed.

The four bopressure aptightened apump via in

The intermechamber aintermediateweep hole h

Fig 24

nnet studs are simultaneously stretched to the correct pre-load by hydraulicplied behind a piston which acts on a load rod in the stud. The nut is thennd pressure is released. Pressure is supplied by an air powered hydraulicternal porting in the BOP body. See Fig 25

U II BLOWOUT PREVENTER HYDRAULIC CONTROL SYSTEM

ection 2.doc © MTC

Fig 25

diate flange is the barrier between the well bore and the hydraulic operatingnd contains the seals around the operating shaft. In the bottom of the flange a weep or vent hole is positioned witch must always be clean. Theas several functions:


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1. During pressure test of the ram BOP leakage through the weep holeindicates worn seals against the wellbore and require immediately changeout prior to commence operation.

2. Leakage during pressure test of the hydraulic chamber indicates worn sealagainst the hydraulic operating side and require immediately change outprior to commence operation.

3. The weep hole avoid 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 leakagedt
uring a well control situation the secondary can be engaged by injecting plastic packing
hrough a packing ring that will seal against the well bore. See Fig 26.

Fig 26

All ram BOP’s must be equipped with a ramlock system that can either be manual operated


or hydraulic operated to assure that the ramdoes not open if the hydraulic closing pressureis lost. If it is a manuel system it should beequipped with extension hand wells.For hydraulic operated system Cameron isusing the wedge-lock system.The “U-II” wedge-locks act directly on theoperating piston tailrod. The operating systemcan be interlocked using sequence caps toensure that the wedge-lock is opened beforepressure is applied to open the BOP. See Fig27

Fig 27


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06.05 Cameron ram assembly

All BOP manufactures supply three different type of rams:

Fixed ram assemblies.Variable ram assemblies.

Rfrc

F

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 lock the frontpacker in place. See Fig 28.

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

Fig 28

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

Variable ram assembly


ig 29

© MTC

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 areused. A set of variable bore rams ina stack provides backup for two ormore sizes of standard pipe rams orserves as the primary ram for onesize and the backup for the other.See Fig 29.


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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 aupper 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) is

Importance of

Packer pressure is thewhen closing hydraulicFor a ram assembly tothe wellbore pressure pressure generates seis sufficient to initially the packer pressure riupon the ram blocks. above wellbore pressu

Fig 31

When we have a wornis not able to generate

© MTC

inserted to lock the side packers.See Fig 30.

Fig 30

ram packer pressure

internal elastomer compressive force generated in the ram packers pressure drives the ram assemblies into contact with each other. contain wellbore pressure the packer pressure must be higher thantrying to get past the rubbers. Typically, closing hydraulic operatingveral thousand psi elastomer pressure inside the ram packers. Thiscontain wellbore pressure. See Fig 31. As wellbore pressure rises,ses as well due to the closing effect that the wellbore pressure hasSee Fig 32. With this mechanism, packer pressure is maintainedre.

Fig 32

out ram cavity or worn ram rubbers, the closing operating pressure the required packer pressure with a leak resulting.


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Feedable rubber

All of the major ram type BOP manufactures use the feedable rubber design concept intheir ram packers. This includes Cameron, Hydril, Shaffer and MH Koomey. Extrusionplat s moulded into the front packer into the front packer serves several purpose:

A nlarg

A mc a

Thestillapp

Al

07.

Thestemposramclos

e

To support the rubber to prevent unwanted extrusiondue to wellbore forces in the vertical direction.

Act as pistons to extrude feedable rubber to the point of pipe contact. See Fig 33.

Fig 33

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

oderately worn packer still retains a large but reduced volume of feedable rubber. Therance between the ram and pipe is reduced at the seal off position.

le

F Surfa

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

l ram type BOP’s are only designed to contain and seal Rated Working Pressurefrom below the ram.

05 Operating Ratio

first ram preventers used in drilling operations were manually operated. Threadeds were provided to move ram blocks back and forth between the open and close

ition It soon became apparent that a faster operating method was needed to close thes we or

.

ce\3\1\Section 2.doc © MTC

hen a well kicked. This led to the development of hydraulic operated pistons to open the rams.


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In Fig 34 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 34

C

Wmfcp

F

Tpf

RAMPISTON

RAM SHAFT

CLOSING CHAMBER

OPENING CHAMBER

:\IWCF

losing Ratio

A dimensionless factor equal to the wellbore pressure divided by the operatingpressure necessary to close the ram BOP against wellbore pressure.

hen closing the rams, hydraulic closing pressure acting on the ram operating piston areaust overcome the wellbore pressure acting on the ram shaft area which is attempting to

orce the ram in to open position. This ratio exists because of difference in areas that thelosing hydraulic pressure acts upon compared to the ram rod area exposed to wellboreress re. See Fig 35.

ig 35

e ressormu

PRE

u

Closing ratios are generally in therange from 6:1 to 9:1. This means thatit takes 1 psi of closing hydraulicpressure per 6 to 9 psi wellborepressure to close the preventer.Stated in another way, on a preventerwith closing ratio of 6:1, if the wellborepressure is 3.000 psi it should take500 psi hydraulic pressure to close thepreventer.

extreme case is closing the ram preventer while it is exposed to maximum rated

WELLSSURE

RAM SHAFTAREA

CLOSINGAREA

CLOSINGPRESSURE

h


ure in the wellbore. This required closing pressure is calculated by the followingla:

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


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Opening Ratio

A dimensionless factor equal topressure necessary to open

Opening rams under pressure information and un

When opening rams, hydraulic openinmust overcome the wellbore pressurew llbore pressure is holding the ramsb cks is fairly large, so the opening rand 4:1 are common. Some preventethat the opening pressure much exceed

The extreme case is opening the rampressure in the wellbore. This requireformula:

08.05 BOP end and Side Outlet Con

On all type of BOP’s three different typand side outlet connections. This inspools, casing spools and hydraulic coand flanged connection. See Fig 36,37

RAM BLOCKRESULTANT

RAMRESU

Opening pressure required toopen rams with rated workingpressure in the wellbore

the wellbore pressure divided by operatinga ram BOP containing wellbore pressure.

is not recommended. The following are forderstanding purposes only!!!!!

g pressure acting on the ram operating piston area acting on the back side of the ram blocks. This in the closed position. The area behind the ramatios are much lower. Opening ratios between 1:1

elo

© MTC

rs have opening ratios less than 1:1 which means the wellbore pressure.

In Fig 36 is an exposed view showingforces on a ram block and ram shaftwhile containing pressure below the ramcavity. The packer is sealed on pipe andopening force is being applied to theoperating piston.

Fig 36

preventer while it is exposed to maximum ratedd opening pressure is calculated by the following

nections

es of connections is used both as end connectionscludes ram preventer, annular preventer, drillingnnectors. The three types are Studded, Clamp Hub,38.

Studded Connection

Fig 36

SHAFTLTANT

Rated Working Pressure= ------------------------------------- Opening Ratio


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Clamp Hub Connection

Fig 37

09.05

Two

API T

API Tface seali

The f


Flanged Connection

Fig 38

API Type Flanges

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

API Type 6B Flange

ype 6B flange is a “low” pressured flange with maximum pressure rating of 5.000 psi.

ype R or RX ring gaskets are used for this type flange and does not allow face tocontact between hubs or flanges, so external loads are transmitted through the

ng surfaces of the ring.

lange face might be flat or raised. See Fig 39.

Fig 39FLANGE SECTIONINTERGRAL FLANGE

TOP VIEW


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API Type 6 BX Flange

API Type 6 BX flange is a “high” pressure flange with maximum pressure rating of 20.000psi.

API Type BX ring gaskets are used for this type of flange allowing face to face contact ofthe flanges.

The flange face shall be raised except for studded flanges which may have flat faces. SeeFig 40.

Fig 40

RATED WORKING PRESSURE

FLANGE SIZE RANGETYPE 6 B TYPE 6 BX

2.0003.0005.000

10.00015.00020.000

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

A cording to API the following marking should be visible on the flanges OD:

FLANGE SECTIONINTERGRAL FLANGE

TOP VIEW

c


Manufacturer’s name and markAPI monogramSizeThread sizeEnd and outlet connection sizeRated working pressureRing gasket type and numberRing gasket material


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M:\I

10.05 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 thegaskets 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 SType 304 Stainless Steel 160 S 304Type 316 Stainless Steel 140 to 169 S 316Inconel 625 481 to 560

API Type “R” Ring Joint Gasket

This type “R” ring joint gasket is not energized by internal pressure. Sealing takes placealo g small bands of contact between grooves and the gasket on both the OD and ID ofthdear

Vigris tig

n

WCF Surface\3\1\Section 2.doc © MTC

e gasket. The gasket may be either octagonal or oval in cross section. The Type “R”sign does not allow face to face contact between hubs and flanges, so external loadse transmitted through the sealing surfaces of the ring.

bration and external loads may cause small bands of contact between the ring and theoove to deform plastically, so that the joint may develop a leak unless the flange boltingperiodically tighten. Standard procedure with type “R” joints in the BOP stack is tohten the flange bolting weekly. See Fig 41/43.

Fig 41

Type R Type RX


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API Type “RX” Pressure-Energised Ring Joint 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 41/43.

API Type “BX” Pressure-Energised Ring Joint 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 tolerancerange, 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 42/43.

MARKING Fig 42

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

Type BX


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M

TpgcgjmIS


Fig 43

API

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

oint gaskets are included in API Specification 6A and in API Specification 16A. Gasketaterials, coatings and platings should be in accordance with API Specification 6A.

dentification markings should be in accordance with API Specification 6A and APIpecification 16A.


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06 Choke Manifold

01.06 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 44.

Fig 44

02.06 Choke Manifold – Installation

Recommended practices for installation of choke manifolds for surface installationsinclude:

Manifold equipment subject to well and/or pump pressure (normally upstream of andincluding the chokes) should have a working pressure equal to or greater than the ratedworking pressure of the ram BOPs in use.

For working pressures of 3,000 psi and above, flanged, welded, clamped should beemployed on components subjected to well pressure.

The choke manifold should be placed in a readily accessible location, preferably outsidethe rig substructure.


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M:\IWCF

Buffer tanks are sometimes installed downstream of the choke assemblies for the purposeof manifolding the bleed lines together.

All choke manifold valves should be full bore. Two valves are recommended between theBOP stack and the choke manifold for installations with rated working pressures of 5,000psi and above. One of these two valves should be remotely controlled. During operations,all valves should be fully opened or fully closed.

A minimum of one remotely operated choke should be installed on 10,000 psi, 15,000 psiand 20,000 psi rated working pressure manifolds.

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

Pressure gauges suitable for operating pressure and drilling fluid service should beinstalled so that drill pipe and annulus pressures may be accurately monitored and readilyobserved at the station where well control operations are to be conducted.

03.06 Choke Lines – Installation

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:

Be as straight as possible.

MinimarranMinimshouLineThe the cmainto re

04.0

Kill likill licircuthe d


Be firmly anchored to prevent excessive whip or vibration.

Have a bore of sufficient size to prevent excessive erosion or fluid friction:

um recommended size for choke lines is 2” nominal diameter for 3K and 5Kgements and 3” nominal diameter for IOK, 15K, and 20K arrangements.um recommended nominal inside diameter for lines downstream of the chokes

ld be equal to or greater than the nominal connection size of the chokes.s downstream of the choke manifold are not normally required to contain pressure .bleed line (the line that bypasses the chokes) should be at least equal in diameter tohoke line. This line allows circulation of the well with the preventer closed whiletaining a minimum back pressure. It also permits high volume bleed off of well fluidslieve casing pressure with the preventer closed.

6 Kill Lines – Installation

nes are an integral part of the surface equipment required for drilling well control. Thene system provides a means of pumping into the wellbore when the normal method oflating down through the kelly or drill pipe cannot be employed. The kill line connectsrilling fluid pumps to a side outlet on the BOP stack. The location of the kill line


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M:\IWCF Surface\3\1\Section

connection 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 orinaccessible. This line normally is tied into the kill line near the blowout preventer stackand extended to a site suitable for location of a pump. This site should be selected toafford maximum safety and accessibility.

The same guidelines which govern the installation of choke manifolds and chokelines apply to kill line installations.

05.06 HCR – Side Outlet Valves

Two valves are recommended between the BOP stack and the choke manifold forinstallations with rated working pressures of 5,000 psi and above. One of these two valvesshould be remotely controlled. During operations, all valves should be fully opened or fullyclosed.

Of the two valvcoming from tSee Fig 45.

The outside vaUnit or from reoperating pres

2.doc

es installed on the BOP side outlet the manual valves is installed as the firsthe BOP and is always left in open position during normal drilling operation.

Fig 45

Fig 46

lve mo

sure

© MTC

is a hydraulic operated valve, which can be operated from the Controlte operation panels using 1.500 psi operating pressure. The maximum of the valves is normally 3.000 psi. See Fig 46.


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06.06 Chokes

The purpose of the chokes in the overall BOP system is to control back pressure in thewellbore while circulating out a kick. The chokes might either be manual and/or hydraulicoperated. A minimum of one remotely operated choke should be installed on 10,000 psi,15,000 psi and 20,000 psi rated working pressure manifolds.

The choke control station, whether at the choke manifold or remote from the rig floor,should be as convenient as possible and should include all monitors necessary to furnishan overview of the well control situation. The ability to monitor and control from the samelocation 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 47

Cameron hydraulically actuated drilling choke are available in working pressures from5.000 psi to 20.000 psi. See Fig 47.

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.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 21.500 lbs at the gate.

Fig 48

Hydraulic actuator

Position indicator


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Cameron manually actuated choke are available in working pressures from 5.000 psi to20.000 psi See Fig 48.

Thrust bearings in the actuator provide low torque handwheel operation. Upstreampressure has no thrust loading on the actuator, only downstream pressure affects thetorque.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.

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.

7.06 Hydrates
0

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 upinto large pieces of solid hydrate at bends or restrictions, such as chokes or other valves.See Fig 49.

GAS + WATER (VAPOUR)

SOLID HYDRATEBUILD-UP

Fig 49

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 SCF compressed gas.This can be released when the hydrate is melted by the application of heat. Once hydrateshave formed they may lead to complete plugging of chokes, fail-safe valves, choke linesand expansion points at entry to the MGS. It is normal to try to prevent hydrates fromforming by the injection of a suppressant at the upstream side of 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


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M

(-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 upstreamo the choke at the choke manifold. This is done by a glycol injection pump which candsfDf

0

Di

Aaeol

f


eliver at a pressure up to the rated pressure of the choke manifold. The injection istarted at a point when the gas influx is some depth below the BOP, such as 1500 to 2000t. The minimum injection rate is about .05 gpm but should be increased as necessary.uring severe problems with hydrates Methanol might be injected as it has a lower

reezing point than Glycol.

8.06 Mud/Gas Separator

The mud/gas separator is the primary means ofremoving gas from the drilling fluid. There areseveral advantages to removing a large percentageof the gas from the drilling fluids before the drillingfluid flows to the degasser tank at the sand traparea and the pit room. See Fig 50.The primary reason is to reduce the quantity of gaswhich may percolate out of the drilling fluid in themud pits an begin the process of regaining theproper density.

As the atmospheric mud/gas separator is theprimary type used, there are two types ofatmospheric designs which are available. Thevertical type and the horizontal type.

The horizontal type is gaining recognition within theindustry because of it’s design advances and theyare:

a.Larger exposed liquid surface area.b.Longer retention time of the fluid.c.The gas flows perpendicular to the direction of the

ue to space problems thndustry.

s the gas and drilling flutmosphere. It can be sxtends 150 ft above thef 8 psi. The 8 psi back p

ine. Many variables mus

© MTC

fluid flow.

Fig 50

e vertical mud/gas separator is still the most common used in the

id is separated the gas flows up through the vent stack into thehown that for the average 6” schedule 80, 5.85” ID pipe, that mud/gas separator there is a back pressure reading in the rangeressure is at the transition from the mud/gas separator to the ventt be taken into account in the calculations to this back pressure,


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such as the size and length of line in which the gas flowing, compressed isothermal flow,relative roughness, friction factors for the pipe and Reynolds numbers. However this 8 psigauge pressure can be calculated and is fairly representative of actual situations. Due tothe high friction loss in the vent line 10” to 12” lines are normally used.

The objective of the dip tube or U-tube is toexert a hydrostatic head by column of fluidwhich will create a greater resistance toflow than the vent line going up the derrick.The design objective is to assure oneselfthat the path of least resistance is alwaysthrough the derrick vent line. Consideringthat the dip tube or U-tube is always full offluid when flowing gas through the mud/gasseparator, the worst case will be with waterin the tube which is often mounted belowthe mud/gas separator. As shown on atypical vertical mud/gas separator drawing,where the dip tube goes into the trip tank,the trip tank frequently has a centrifugalhole fill pump installed at it’s base as wellas a float and wireline extending to the rigfloor and used as a trip tank indicator. SeeFig 51

A U-tube does not have an indicatorinstalled, but a pressure gauge.

Fig 51

Even that most mud gas separators have a design pressure of 150 psi the actualmaximum operating pressure is below psi depending of the high of the U-/Dip Tube andthe fluid it contains.

Eks: High of U-tube 15 feetFluid gradient 0.465 psi/ftSafety factor 0.75

09.06 Degasser

Degassers are the secondary means of removing gas from gas cut drilling fluid. The twomost predominant types of secondary degassers are the WELLCO and the SWACO. SeeFig 52.

15 x 0.465 x 0.75 = 5.2 psi


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Fig 52

A degasser may be used to remove entrained gas bubbles in the drilling fluid that are tosmall to be removed by the mud/gas separator. Most degassers make use of some degreeof vacuum to assist in removing this entrained gas. The drilling fluid inlet line to thedegasser should be placed close to the drilling fluid discharge line from the mud/gasseparator to reduce the possibility of gas breaking out of the drilling fluid in the pit.


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07 Control System

01.07 General

BOP control systems for surface installations (land rigs, offshore jack-ups and platforms)normally supply hydraulic power fluid in a closed loop circuit as the actuating medium.The elements of the BOP control system normally include (See Fig 53):

- Storage (reservoir) equipment for supplying ample control fluid to the pumping system.

- Pumping systems for pressurizing the control fluid.- Accumulator bottles for storing pressurized control fluid.- Hydraulic control manifold for regulating the control fluid pressure and directing

the power fluid flow to operate the system functions (BOP's and choke and killvalves).

- Remote control panels for operating the hydraulic control manifold from remote locations. - Hydraulic control fluid.

Fig 53

02.07 Response Time

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 becapable of closing each ram BOP within 30 seconds. Closing time should not exceed 30seconds for annular preventers smaller than 18-3/4” nominal bore and 45 seconds forannular preventers of 18-3/4” and larger. Response time for choke and kill valves (eitheropen or close) should not exceed the minimum observed ram close response time.


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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 effecting aseal. A BOP may be considered closed when the regulated operating pressure hasrecovered to its nominal setting. If confirmation of seal off is required, pressure testingbelow the BOP or across the valve is necessary.

03.07 Storage Equipment

A suitable control fluid should be selected for the system operating medium based on thecontrol system operating requirements, environmental requirements and user preference.

Water-based hydraulic fluids are usually a mixture of portable water and a water solublelubricant additive. When ambient temperatures at or below freezing are expected,sufficient volume of ethylene glycol or other additive acceptable to the control systemmanufacturer should be mixed with the water-based hydraulic fluid to prevent freezing.

The hydraulic fluid reservoir should have a capacity equal to at least twice the usablehydraulic fluid capacity of the accumulator system.

04.07 Pump Requirements

A pump system consists of one, or more pumps driven by a dedicated power source. Two(primary and secondary) or more pump systems should be employed having independentpower sources.

The combined output of all pumps should be capable of charging the entire accumulatorsystem from precharge pressure to the maximum rated control system working pressurewithin 15 minutes.

The same pump system(s) may be used to produce power fluid for control of both the BOPstack and the diverter system

Each pump system should provide a discharge pressure at least equivalent to the systemworking pressure. Air driven pump systems should require no more than 75 psi air supplypressure.

Devices used to prevent pump system over-pressurization should be installed directly inthe control system supply line to the accumulators and should not have isolation valves orany other m ans that could defeat their intended purpose.

Electrical atimes suchdecreased automaticalpressure.

05.07 Accu

Accumulato

e

ection 2.doc © MTC

nd/or air (pneumatic) supply for powering pumps should be available at all that the pumps will automatically start when the system pressure hasto approximately ninety percent of the system working pressure and

ly stop within plus zero or minus 100 psi of the system design working

mulator Bottles and Manifolds

rs are pressure vessels designed to store power fluid.


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Accumulator designs include bladder, piston and float types. Selection of type may bebased on user preference and manufacturer's recommendations considering the intendedoperating environment.

The accumulator system should be designed so that the loss of an individual accumulatorand/or bank should not result in more than approximately twenty-five percent loss of thetotal accumulator system capacity.

Supply pressure isolation valves and bleed down valves should be provided on eachaccumulator bank to facilitate checking the precharge pressure or draining theaccumulators back to the control fluid reservoir.

The precharge pressure in the system accumulators serves to propel the hydraulic fluidstored in the accumulators for operation of the system functions. The amount ofprecharge pressure is a variable depending on specific operating requirements of theequipment to be operated and the operating environment, but most common 1.000 psi.

Because of the presence of combustible components in hydraulic fluids, accumulatorsshould be precharged only with nitrogen.

06.07 Hydraulic Control Manifold

The hydraulic control manifold is the assemblage of hydraulic control valves, regulatorsand gages from which the system functions are directly operated. It allows manualregulation of the power fluid pressure to within the rating specified by the BOPmanufacturer. The hydraulic control manifold provides direct pressure reading of thevarious supply and regulated pressures.

A dedicated control circuit on the hydraulic control manifold should operate the annularBOP(s). The components in this circuit should include a pressure regular to reduceupstream manifold pressure to the power fluid pressure level that meets the BOPmanufacturer's recommendations. The regulator should respond to pressure changes onthe downstream side with sensitivity, sufficient to maintain the set pressure within plus orminus one hundred and fifty psi.

The annular BOP pressure regulator should be remotely controllable. Direct manual valveand regulator operability should permit closing the annular BOP and/or maintaining the setregulated pressure in the event of loss of the remote control capability. See Fig 54

Fig 54

Old Type AnnularPressure Regulator

New Type AnnularPressure Regulator


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The hydraulic control manifold includes a common power fluid circuit with pressurer gulation and control valves for operation of the ram type BOP's and choke and killv lves. This circuit may be provided with a manifold regulator bypass valve or othermdpp

PBTpm

Pic

0

S

1

3

4

6

11

1

1

1

1

2

2

2

ea


eans to override the manifold regulator to permit switching from regulated pressure toirect accumulator pressure for operating functions. The regulator should respond toressure changes on the downstream side with sensitivity, sufficient to maintain the setressure within plus or minus one hundred and fifty psi.

lacing the control valve handle on the right side (while facing the valve) should close theOP or choke or kill valve, the left position should open the BOP or choke or kill valve.he center position of the control valve is called the "block" position. In the block position,ower fluid supply is shut off at the control valve. The other ports on the four-way valveay be either vented or blocked depending on the valve selected for the application.

rotective covers or other means which do not interfere with remote operation should benstalled on the blind/shear ram and other critical function control valves. Lifting of theseovers is required to enable local function operation.

7.07 Schematic of Control System

ee Fig 55.

. Customer Air Supply. Normal air supply is at 125 psi.

. Bypass Valve. To automatic hydro-pneumatic pressure switch. When pressures higher than the normal 3.000 psi are required.

. Automatic Hydro-Pneumatic Pressure switch. Pressure switch is set at 3.000 psi cut-out and @ 2.700 psi cut-in.

. Air Operated Hydraulic Pumps.Normal operating air pressure is 125 psi.

0. Electric Motor Driven Triplex Pump Assembly.1. Automatic Hydro-Electric Pressure Switch.

Pressure switch is set at 3.000 psi cut-out and @ 2.700 psi cut-in.2. Electric Motor Starter.

Works in conjunction with the automatic hydro-electric pressure switch.6. Accumulator Shut Off Valve.

Manually operated.7. Accumulators.

Use nitrogen when adding precharge.8. Accumulator Relief Valve..

Valve set to relieve at 3.500 psi.0. Manifold Pressure Reducing and Regulating Valve.

Manually operated. Adjust to the required continuous operating pressure of ram type BOP’s.2. Selector Valve – 3 position/4 way valve.

With air cylinder operators for remote operation from the control panels. 3. Bypass Valve.

With air cylinder operator for remote operation from the control panels. Kept closed unless 3.000 psi is required on the ram type BOP’s


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Fig 55

© MTC


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26. Panel – Unit Selector.Used to allow pilot air pressure to the annular preventer reducing and regulating valve either from the air regulator on the unit or from the air regulator on the remote control panel.

27. Annular Pressure Reducing and Regulating Valve.Reduces the accumulator pressure to the required annular operating pressure. Pressure can be varied for pipe size and operation carried out.

28. Accumulator Pressure Gauge.29. Manifold Pressure Gauge.30. Annular Preventer Pressure Gauge.31. Pneumatic Pressure Transmitter for Accumulator Pressure.32. Pneumatic Pressure Transmitter for Manifold Pressure.33. Pneumatic Pressure Transmitter for Annular Preventer Pressure.35. Air Regulator for Annular Pressure Reducing and Regulating Valve.36. Air Regulator for Pneumatic Pressure Transmitter for Annular Pressure.37. Air Regulator for Pneumatic Pressure Transmitter for Accumulator Pressure.38. Air Regulator for Pneumatic Pressure Transmitter for Manifold Pressure.41. Hydraulic Fluid Fill Hole.

08.07 Remote Control Panel

A minimum of one remote control panel should be furnished. This is to ensure that thereare at least two locations from which all of the system functions can be operated. Theremote panel should be accessible to the Driller to operate functions during drillingoperations. The Driller's remote control panel display should be physically arranged as agraphic representation of the BOP stack. See Fig 56.

Fig 56

Its capability should include the following:

1. Control all the hydraulic functions which operate the BOP's and choke and kill valves.

2. Display the position of the control valves and indicate when the electric pump is running (offshore units only).

3. Provide control of the annular BOP regulator pressure setting.


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4. Provide control of the manifold regulator bypass valve or provide direct control of themanifold regulator pressure setting.

5. The driller's panel should be equipped with displays for readout of:Accumulator pressureManifold regulated pressureAnnular BOP regulated pressureRig air pressure

6. Offshore rig driller's panels should have an audible and visible alarm to indicate thefollowing:

Low accumulator pressureLow rig air pressureLow hydraulic fluid reservoir levelPanel on standby power (if applicable)

7. All panel control functions should require two handed operation. Regulator controlmay be excluded from this requirement.

The BOP stack functions should also be operable from the main hydraulic controlmanifold. This unit should be installed in a location remote from the drill floor andeasily accessible to rig personnel in an emergency.

Remote control from the remote panels of the hydraulic control manifold valves may beactuated by pneumatic (air), hydraulic, electro-pneumatic, or electro-hydraulic remotecontrol systems. The remote control system should be designed such that manualoperation of the control valves at the hydraulic control unit will override the positionpreviously set by the remote controls.

09.07 Accumulator Volumetric Requirements

The BOP control system should have a minimum stored hydraulic fluid volume, withpumps inoperative, to satisfy the greater of the two following requirements:

Close from a full open position at zero wellbore pressure, all of the BOP's inthe BOP stack, plus fifty percent reserve.

The pressure of the remaining stored accumulator volume after closing all ofthe BOP's should exceed the minimum calculated (using the BOP closing ratio)operating pressure required to close any ram BOP (excluding the shear rams) atthe maximum rated wellbore pressure of the stack.

The about mentioned requirements are from API (RP 16E) and are just guidelines.The actual volumetric requirements depends on working area, national rules andcompany policy and can vary a lot.


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10.07 Accumulator Volumetric Capacity

For the purpose of this section, the following definitions apply:

Stored Hydraulic Fluid. The fluid volume recoverable from the accumulator system between the maximumdesigned accumulator operating pressure and the precharge pressure.

Usable Hydraulic Fluid. The hydraulic fluid recoverable from the accumulator system between the maximumaccumulator operating pressure and minimum calculated operating pressure or 200 psiabove precharge pressure whichever is greatest.

Minimum Calculated Operating Pressure. The minimum calculated pr ssure to effectively close and seal a ram-type BOP against awellbore pressure equal to tclosing ratio specified for th

Component Minimum OpeThe minimum operating prepreventers under normal op

The equation for vol

where:P1 = Initial PV1 = Initial G

Fig 57

e

© MTC

he maximum rated working pressure of the BOP divided by theat BOP.

rating Pressure Recommended by the Manufacturer. ssure to effectively close and seal ram-type or annular-typeerating conditions, as prescribed by the manufacturer.

umetric capacity calculation according to Boyle’s law is:

P1 x V1 = P2 x V2or

Pressure x Volume = Constant

ressure P2 = Final Pressureas Volume V2 = Final Gas Volume


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Example:

Accumulator bottle size 10 gallons.Precharge pressure 1.000 psi

Initial condition with only gas (See Fig 58a):

Pressure x Volume = Constant1.000 x 10 = 10.000

The pump system is started and hydraulic fluid is pumped into the accumulator bottle untilmaximum operating pressure is reached at 3.000 psi (See Fig 58b):

P1 x V1 = P2 x V2 � 1.000 x 10 = 3.000 x V2

Stored hydraulic fluid = 10 - 3.33 = 6.66 gal

Fig 58

The pump system is isolated and the BOP’s functioned until accumulator pressure reachprecharge pressure + 200 psi (See Fig 58c):

P1 x V1 = P2 x V2 � 1.000 x 10 = 1.200 x V2

V2 = ------------ = 3.3310.0003.000

Fig 58 a Fig 58 b Fig 58 c Fig 58 d Fig 58 eGas Fluid

10 gal

1.000 psi 3.000 psi

3.33 gal

6.66 gal

1.200 psi 1.500 psi 2.110 psi

8.33 gal

1.66 gal

6.66 gal

3.33 gal

4.74 gal

5.26 gal

V2 = ------------ = 8.3310.0001.200


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Usable hydraulic fluid = 8.33 - 3.33 = 5 gal

If the minimum operating pressure recommended by the manufacture is 1.500 psi as forShaffer Annular Preventer with pipe size smaller than 7” the usable hydraulic fluid wouldbe (See Fig 58d):

P1 x V1 = P2 x V2 � 1.000 x 10 = 1.500 x V2

Usable hydraulic fluid = 6.66 - 3.33 = 3.33 gal

If the minimum calculated operating pressure to effectiveagainst maximum wellbore pressure is used the usable 58e):

Shaffer 15.000 psi Bop with closing ratio 7.11Minimum operating pressure = 2110 psi

P1 x V1 = P2 x V2 � 1.000 x 1

Usable hydraulic fluid = 4.74 - 3.33 = 1.41 gal

To determine the total number of accumulator bottles ttotal volume according to rules and regulations to operathe calculated usable hydraulic fluid per bottle. Round accumulator bank.

V2 = ------------ = 6.6610.0001.500

V2 = ------------ = 4.7410.0002.110

ly close and seal a ram-type BOPhydraulic fluid would be (See Fig

0 = 2.110 x V2

o be present divide the requiredte the functions on the BOP withoff to next larger whole bottle or

© MTC


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08 Auxiliary Equipment

01.08 Kelly Valves

An upper kelly valve is installed between the swivel aninstalled immediately below the kelly. See Fig 59/60.

Fig 59

Fig 60

02.08 Top Drive Valves

There are two ball valves (sometimes referred to as kelltop drive equipment. The upper valve is air or hydraulicdriller's console. The lower valve is a standard ball kellysafety valve) and is manually operated, usually by meanGenerally, if it becomes necessary to prevent or stop flooperations, a separate drill pipe valve should be used valves. However, flow up the drill pipe might prevent statop drive with its valves can be used, keeping in mind the

a. Once the top drive's manual valve is installed, closed, and the top drive disconnected, a crossover may be required to install an inside BOP on top of the manual valve.

b. Most top drive manual valves cannot be stripped into 7 5/8 inch or smaller casing.

c. Once the top drive's manual valve is disconnected from the top drive, another valve or spacer must be installed to take its place.

See Fig 61.

Fig 61

d the kelly. A lower kelly valve is

y valves or kelly cocks) located onally operated and controlled at the valve (sometimes referred to as as f a large hexagonal wrench.w

rab

o

© MTC

up the drill pipe during trippingther than either of the top drivebing this valve. In that case, thefollowing cautions:


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M:\I

03.08 Drillpipe Safety Valve (FOSV)

A spare drill pipe safety valve should be readilyavailable (i.e., stored in open position withwrench accessible) on the rig floor at all times.This valve or valves should be equipped toscrew into any drill string member in use. Theoutside diameter of the drill pipe safety valveshould be suitable for running into the hole. SeeFig 62.

Fig 62

04

AnvaavstsueqmSI

1.2.3.4.

WCF Surface\3\1\Section 2.doc

.08 Inside Blowout Preventer (IBOP or GREY Valve)

inside blowout preventer, drill pipe floatlve, or drop-in check valve should beailable for use when stripping the drillring into or out of the hole. The valve(s),b(s), or profile nipple should beuipped to screw into any drill stringember in use. No direct read-out ofDPP can be obtained. See Fig 63.

Release Tool BodyValve Release RodValve SpringValve Seat

© MTC


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Fig 63

05.08 Drillstring Float Valve

A float valve is placed in the drill string to prevent upward flowstring. The float valve is a special type of back pressure or cgood working order will prohibit backflow and a potential blow

The drill string float valve is usually placed in the lowermost pbetween two drill collars or between the drill bit and drill collavents the drill string from being filled with fluid through the bitdrill string must be filled from the top at the drill floor, to preveTripping time will be increased and excess surge pressure crvalves. No direct read-out of SIDPP can be obtained.

There are two types of float valves:

a. The flapper-type float valve offers the advantage of hathe valve that is approximately the same inside diameThis valve will permit the passage of balls, or go-devilfor operation of tools inside the drill string below the flo

b. The spring-loaded ball, or dart, and seat float valve ofinstantaneous and positive shut off backflow through t

Fig 64

Fig 65

of fluid or gas inside the drillheck valve. A float valve inout through the drill string.

ortion of the drill string,r. Since the float valve pre- as it is run into the hole, thent collapse of the drill pipe.eated when running with float

ving an opening through ter s that of the tool joint. s, wat

ferhe

a

© MTC

hich may be required valve. See Fig 64.

s the advantage of an drill string. See Fig 65.


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06.08 Test Plug

A test plug is used to test BOP’s andassociated well control equipment withoutexerting pressure on well head and casing.When using test plug well head side outletvalves should be open to avoid damage tocasing and formations. See Fig 66.

Fig 66

07.08 Cup Type Tester

A cup type tester is used to test well head andwell head side outlet valves without exertingpressure on casing and formation. Cup typetester should be run on open ended drill pipeto release any build up of pressure below thecup. See Fig 67.

Fig 67

08.08 Triptank

A trip tank is a low-volume, [100 barrels or less] calibrated tank that can be isolated fromthe remainder of the surface drilling fluid system and used to accurately monitor theamount of fluid going into or coming from the well. A trip tank may be of any shapeprovided the capability exists for reading the volume contained in the tank at any liquidlevel. The readout may be direct or remote, preferably both. The size and configuration ofthe tank should be such that volume changes on the order of one-half barrel can be easilydetected by the readout arrangement. Tanks containing two compartments with monitoring


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arrangements in each compartment are preferred as this facilitates removing or addingdrilling fluid without interrupting rig operations.

Other uses of the trip tank include measuring drilling fluid or water volume into the annuluswhen returns are lost, monitoring the hole while logging or following a cement job,calibrating drilling fluid pumps, etc. The trip tank is also used to measure the volume ofdrilling fluid bled from or pumped into the well as pipe is stripped into or out of the well.

09.08 Pit Volume Measuring Devices

Automatic pit volume measuring devices are available which transmit a pneumatic orelectric signal from sensors on the drilling fluid pits to recorders and signaling devices onthe rig floor. These are valuable in detecting fluid gain or loss.

10.08 Flow Rate Sensor

A flow rate sensor mounted in the flow line is recommended for early detection offormation fluid entering the wellbore or a loss of returns.


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09 Recommended Pressure Test Practices 01.09 Initial Test (Prior to spud or upon installation)

Component to beTested

RecommendedPressure Test

Low Pressure – psi


High Pressure – psi

Rotating Head 200 – 300 Optional

Diverter Element Minimum of 200 Optional

Annular preventer

Operating Chambers

200 – 300

N/A

Minimum of 70% of annularBOP working pressureMinimum of 1500

Ram Preventers Fixed Pipe Variable Bore Blind/blind Shear Operating Chamber

200 – 300200 – 300200 – 300N/A

Working pressure of ram BOP’sWorking pressure of ram BOP’sWorking pressure of ram BOP’sMaximum operating pressurerecommended by ram BOPmanufacturer

Diverter Flowlines Flow Test N/A

Choke Line & Valves 200 – 300 Working pressure of ram BOP’s

Kill Line & Valves 200 – 300 Working pressure of ram BOP’s

Choke Manifold Upstream of Last High Pressure Valve Downstream of Last High Pressure Valve

200 – 300

200 – 300

Working pressure of ram BOP’s

Optional

BOP Control System Manifold and BOP Lines Accumulator Pressure Close Time Pump Capacity Control Stations

N/AVerify PrechargeFunction TestFunction TestFunction Test

Minimum of 3000 N/AN/AN/AN/A

Safety Valves Kelly, Kelly Valves and Floor Safety Valves 200 – 300 Working pressure of

components

Auxiliary Equipment Mud/Gas Separator Trip Tank, Flo-Show etc

Flow TestFlow Test

N/AN/A


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02.09 Subsequent Test (Not to exceed 21 days).

Component to beTested


Low Pressure – psi


High Pressure – psi

Rotating Head N/A Optional

Diverter Element Optional Optional

Annular preventer

Operating Chambers

200 – 300

N/A

Minimum of 70% of annularBOP working pressureMinimum of 1500

Ram Preventers Fixed Pipe Variable Bore

Blind/blind Shear

Casing(prior to running csg) Operating Chamber

200 – 300

200 – 300

200 – 300

OptionalN/A

Greater than the maximumanticipated surface pressureGreater than the maximumanticipated surface pressureGreater than the maximumanticipated surface pressureOptionalN/A

Diverter Flowlines Flow Test N/A

Choke Line & Valves 200 – 300 Greater than the maximumanticipated surface pressure

Kill Line & Valves 200 – 300 Greater than the maximumanticipated surface pressure

Choke Manifold Upstream of Last High Pressure Valve Downstream of Last High Pressure Valve

200 – 300

Optional

Greater than the maximumanticipated surface pressure

Optional

BOP Control System Manifold and BOP Lines Accumulator Pressure Close Time Pump Capacity Control Stations

N/AVerify PrechargeFunction TestFunction TestFunction Test

Optional N/AN/AN/AN/A

Safety Valves Kelly, Kelly Valves and Floor Safety Valves 200 – 300 Greater than the maximum

anticipated surface pressure

Auxiliary Equipment Mud/Gas Separator Trip Tank, Flo-Show etc

Optional Flow TestFlow Test

N/AN/A

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