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Publication No. M07

BLOWOUTPREVENTIONIn CaliforniaEquipment Selection and Testing

California Department of ConservationDivision of Oil, Gas, and Geothermal Resources

STATE OF CALIFORNIAARNOLD SCHWARZENEGGER, Governor

RESOURCES AGENCYMIKE CHRISMAN, Secretary

DEPARTMENT OF CONSERVATIONBRIDGETT LUTHER, Director

This manual is for guidance in establishingblowout prevention requirements. Nothingherein is to be regarded as an approval ordisapproval of any specific product.

HAL BOPP, State Oil and Gas SupervisorDIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES

byPeter R. Wygle

Tenth Edition, 2006Ninth Edition, 2001Eighth Edition, 1998

Seventh Edition, 1997Sixth Edition, 1995Fifth Edition, 1985

Fourth Edition, 1981Third Edition, 1980

Second Edition, 1978First Edition, 1977

California Department of ConservationDivision of Oil, Gas, and Geothermal Resources

Sacramento

BLOWOUT PREVENTIONin California

Equipment Selection and Testing

LEGENDOil & Gas DistrictsGeothermal Districts

OIL AND GAS DISTRICT OFFICESHeadquarters 801 K St., MS 20-20, Sacramento, CA 95814-3530

Phone: 916-445-9686, TDD: 916-324-2555Fax: 916-323-0424

District No. 1 5816 Corporate Ave., Suite 200, Cypress, CA 90630-4731Phone: 714-816-6847Fax: 714-816-6853

District No. 2 1000 S. Hill Rd., Suite 116, Ventura, CA 93003-4458Phone: 805-654-4761Fax: 805-654-4765

District No. 3 5075 S. Bradley Rd., Suite 221, Santa Maria, CA 93455Phone: 805-937-7246Fax: 805-937-0673

District No. 4 4800 Stockdale Hwy., Suite 417, Bakersfield, CA 93309Phone: 661-322-4031Fax: 661-861-0279

District No. 5 466 N. Fifth St., Coalinga, CA 93210Phone: 559-935-2941Fax: 559-935-5154

District No. 6 801 K St., MS 20-22, Sacramento, CA 95814-3530Phone: 916-322-1110Fax: 916-322-1201

GEOTHERMAL DISTRICT OFFICES

Headquarters & 801 K St., MS 20-21, Sacramento, CA 95814-3530District No. G1 Phone: 916-323-1788

Fax: 916-323-0424

District No. G2 1699 W. Main St., Suite E, El Centro, CA 92243-2235Phone: 760-353-9900Fax: 760-353-9594

District No. G3 50 D St., Room 300, Santa Rosa, CA 95404Phone: 707-576-2385Fax: 707-576-2611

CONTENTS

1. SCOPE ............................................................................................................................2. CLASSIFICATION AND SELECTION OF EQUIPMENT .......................................... 2

GENERAL ............................................................................................................... 2-1Classification and Selection System .................................................................... 2-1aComplete BOPE Classification............................................................................ 2-1bProposed Well Operation ................................................................................... 2-1cMinimum Equipment ........................................................................................ 2-1dStack Arrangements ........................................................................................... 2-1eBOP Stack Component Codes ............................................................................ 2-1fDiverter System .................................................................................................. 2-1g

CLASSIFICATION OF BLOWOUT PREVENTION EQUIPMENT ........................... 2-2Diverter System .................................................................................................. 2-2aClass I BOPE .......................................................................................................2-2bClass II BOPE ..................................................................................................... 2-2cClass III BOPE ................................................................................................... 2-2dClass IV BOPE .................................................................................................... 2-2eClass V BOPE ..................................................................................................... 2-2f

CLASSIFICATION OF HOLE-FLUID MONITORING EQUIPMENT ...................... 2-3Class A ............................................................................................................... 2-3aClass B ................................................................................................................2-3bClass C ............................................................................................................... 2-3c

SELECTION OF BOPE AND HOLE-FLUID MONITORING EQUIPMENT ............ 2-4SELECTION OF PRESSURE RATING ..................................................................... 2-5

Maximum Predicted Casing Pressure (MPCP) ................................................... 2-5aMaximum Allowable Casing Pressure (MACP) ................................................. 2-5b

ADDITIONAL REQUIREMENTS ............................................................................ 2-6BOPE Inspection ................................................................................................. 2-6aBOPE Practice Drills and Training Sessions ........................................................ 2-6bRecords ............................................................................................................... 2-6c

3. EQUIPMENT DESCRIPTIONS, OPERATING CHARACTERISTICS, AND REQUIREMENTS .......................................................... 3

GENERAL ............................................................................................................... 3-1PREVENTERS .......................................................................................................... 3-2

Annular or “Bag” Preventers .............................................................................. 3-2aRam Preventers .................................................................................................. 3-2bClosed Preventers ............................................................................................... 3-2c

THE ACTUATING SYSTEM .................................................................................... 3-3Accumulator Unit (Closing Unit) ....................................................................... 3-3aEmergency Backup System ................................................................................ 3-3bControl Manifold ................................................................................................ 3-3cRemote Station(s) .............................................................................................. 3-3dHydraulic Control Lines ..................................................................................... 3-3eHydraulic Fluid .................................................................................................. 3-3f

THE CHOKE AND KILL SYSTEM .......................................................................... 3-4Choke Line and Manifold ................................................................................... 3-4aKill Line .............................................................................................................. 3-4b

AUXILIARY EQUIPMENT ...................................................................................... 3-5Fill-up Line ......................................................................................................... 3-5aStandpipe ........................................................................................................... 3-5bKelly Cock(s) ...................................................................................................... 3-5cPipe Safety Valve ............................................................................................... 3-5dInternal Preventer ............................................................................................... 3-5e

HOLE-FLUID MONITORING EQUIPMENT .......................................................... 3-6Class A ............................................................................................................... 3-6a

SECTION PARAGRAPH PAGE

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181818181921212126293131333333353636363637373739

SECTION PARAGRAPH PAGE

Class B .....................................................................................................................3-6bClass C ..................................................................................................................... 3-6c

3A. SUBSEA BOPE INSTALLATION ................................................................................... 3AGENERAL .................................................................................................................. 3A-1THE DIVERTER SYSTEM .......................................................................................... 3A-2

Purpose ................................................................................................................ 3A-2aInstallation and Equipment Requirements ........................................................... 3A-2b

THE BLOWOUT PREVENTER STACK ..................................................................... 3A-3Variance from Surface Installations ...................................................................... 3A-3aAPI Stack Component Codes ................................................................................ 3A-3bStack Arrangements ............................................................................................. 3A-3cPressure Rating Requirements .............................................................................. 3A-3dPipe Stripping Arrangements ............................................................................... 3A-3e

SUBSEA ACTUATING SYSTEM ............................................................................... 3A-4Variance from Surface Installations ...................................................................... 3A-4aAccumulator Units ............................................................................................... 3A-4bHydraulic Fluid Mixing System............................................................................ 3A-4cAccumulator Charging Pumps ............................................................................. 3A-4dThe Hydraulic Control System ............................................................................. 3A-4eThe Electrohydraulic Control System ....................................................................3A-4fThe Control Stations ............................................................................................. 3A-4gHose Bundles and Hose Reels .............................................................................. 3A-4hSubsea Control Pods .............................................................................................. 3A-4i

CHOKE/KILL LINE VALVE AND PIPING ASSEMBLIES ........................................ 3A-5Riser Line Types ................................................................................................... 3A-5aWellhead Piping and Valves ................................................................................. 3A-5bInstallation Guidelines .......................................................................................... 3A-5c

CHOKE MANIFOLD ................................................................................................. 3A-6Variance from Surface Installations ...................................................................... 3A-6aInstallation Guidelines .......................................................................................... 3A-6b

AUXILIARY EQUIPMENT ........................................................................................ 3A-7General ................................................................................................................. 3A-7aSafety Valves ........................................................................................................ 3A-7bWellhead Connector ............................................................................................. 3A-7cMarine Riser System .............................................................................................3A-7dGuide Structure .................................................................................................... 3A-7eGuideline System................................................................................................... 3A-7f

INSPECTION AND MAINTENANCE OF SUBSEABLOWOUT PREVENTION EQUIPMENT ................................................................. 3A-8

4. GEOTHERMAL EQUIPMENT DESCRIPTIONS, OPERATINGCHARACTERISTICS, AND REQUIREMENTS ................................................................. 4

GENERAL ..................................................................................................................... 4-1GEOTHERMAL ENVIRONMENTS .............................................................................. 4-2

Hot Dry Rock ........................................................................................................... 4-2aHydrothermal ..........................................................................................................4-2b

BOPE DESCRIPTIONS AND REQUIREMENTS ........................................................... 4-3High-temperature Reservoirs .................................................................................. 4-3aLow-temperature Reservoirs ................................................................................... 4-3b

RELATED WELL CONTROL EQUIPMENT ................................................................. 4-4Full-opening Safety Valve........................................................................................ 4-4aUpper Kelly Cock .................................................................................................... 4-4bInternal Preventer .................................................................................................... 4-4c

BOPE TESTING, INSPECTION, TRAINING, AND MAINTENANCE ......................... 4-5Testing ..................................................................................................................... 4-5a

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39394040404040424242424245454545464646464647474747475353535355555556565858

58

6060606060616164646464646666

Inspection and Actuation ............................................................................................ 4-5bCrew Training ............................................................................................................. 4-5cRecords ...................................................................................................................... 4-5dMaintenance ................................................................................................................ 4-5e

5. INSPECTION AND TESTING PROCEDURES ................................................................... 5GENERAL ......................................................................................................................... 5-1

BOPE Inspection and/or Testing Required ................................................................. 5-1aPressure Testing ..........................................................................................................5-1bSuitable Pressure ......................................................................................................... 5-1cTest Results ................................................................................................................ 5-1d

TESTING THE ACTUATING SYSTEM ............................................................................. 5-2Accumulator Unit ....................................................................................................... 5-2aEmergency Backup System ......................................................................................... 5-2bControl Manifold ........................................................................................................ 5-2cRemote Station ........................................................................................................... 5-2d

TESTING THE BOPE STACK, CHOKE AND KILL SYSTEM,AND AUXILIARY EQUIPMENT ...................................................................................... 5-3

General ........................................................................................................................ 5-3aTesting All Connections (except the connection of the annular preventer to theupper ram preventer), the CSO Rams, the Drilling Spool (mud cross), theChoke-manifold Blowdown-line Control Valve, the Choke Bodies, theChoke Downstream Isolation Valves, the Kill-line High-pressure AccessValve, the Casinghead, and the BOPE Test Plug ....................................................... 5-3b

Testing the Kill-line Check Valve ................................................................................ 5-3cTesting the Lowermost Ram Preventer, the Swivel, the Rotary Hose andConnections, and the Standpipe Connections .......................................................... 5-3d

Testing the Upper Pipe-ram Preventer and the Standpipe Valve ................................ 5-3eTesting the Upper Kelly Cock ..................................................................................... 5-3fTesting the Lower Kelly Cock ..................................................................................... 5-3gTesting the Kill-line Control Valve ..............................................................................5-3hTesting the Choke-manifold Outboard Wing Valve(s) and the Kill-line Master Valve ................................................................................................5-3iTesting the Choke-manifold Inboard Wing Valve(s) .................................................... 5-3jTesting the Choke-manifold Blowdown-line Master Valve ......................................... 5-3kTesting the Choke-line Control Valve ..........................................................................5-3lTesting the Choke-line Master Valve ......................................................................... 5-3mTesting the Annular Preventer and the Connection of the Annular Preventer tothe Upper Ram Preventer ..........................................................................................5-3n

Testing the Internal Preventer and the Drill Pipe Full-opening Safety Valve .............. 5-3oSUBSEA BOPE INSPECTION AND TESTING .................................................................. 5-4

Surface Inspection and Testing .................................................................................... 5-4aSubsea Pressure Testing .............................................................................................. 5-4bSubsea Preventer Actuation Testing ............................................................................ 5-4cTesting the Subsea Actuating System ......................................................................... 5-4dTesting the Auxiliary Equipment ................................................................................ 5-4e

APPENDICES

APPENDIX A - General Operating Specifications for Ram-type Preventers ................................ 97APPENDIX B - Table B.1. - General Operating Specifications for Annular Preventers .............. 99

Table B.2. - Approximate Volume of Fluid (US Gallons) Required toClose Annular Preventers on Various-sized Tubular Goods .......... 100

APPENDIX C - General Operating Specifications for Hydraulic Control Valves ......................... 101APPENDIX D - Calculated Internal Yield Pressure of Casing, Drill Pipe, and Tubing ................. 102

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SECTION PAGE

APPENDIX E - Formation Fracturing ............................................................................................. 103APPENDIX F - Fluid Moved vs. Accumulator Pressure for Systems of Various Capacities ........... 104

Figure F.1. - Accumulator Systems with 1,500 psi Working Pressure, 750 psi Nominal Precharge ............... 104Figure F.2. - Accumulator Systems with 2,000 psi Working Pressure, 1,000 psi Nominal Precharge ............ 105Figure F.3. - Accumulator Systems with 3,000 psi Working Pressure, 1,000 psi Nominal Precharge ............ 106

APPENDIX G - API Flange Data ..................................................................................................... 107

SELECTED REFERENCES ................................................................................................................. 108

GLOSSARY OF BOPE AND ASSOCIATED TERMS ....................................................................... 110

SELECTED INDEX ............................................................................................................................ 117

1BLOWOUT PREVENTION IN CALIFORNIA

1. SCOPErized to initiate a blowout drill without the knowledge ofeither the operator’s representative or the contractor’sforeman.)

The operator must post at the well site of each well a copyof the division’s Permit to Conduct Well Operations(Form OG 111). This report contains, among otherprovisions, the class of BOPE required and lists any testsand procedures, including BOPE tests, that must bewitnessed by a division representative.

Section 2 of the manual outlines the division’s require-ments for BOPE, emphasizing the fact that the require-ments are tailored to the individual well.

Section 3 explains the function and operating character-istics of BOPE components. For the purposes of themanual, BOPE components are grouped into five majorfunctional areas: preventers, actuating system, chokeand kill system, auxiliary equipment, and hole-fluidmonitoring equipment. In most cases, a list of divisionrequirements for a component follows the operationalexplanations.

Section 3-A describes the additional equipment andmodification of BOPE components necessary for install-ing and operating blowout prevention equipment on theocean floor.

Section 4 describes the equipment and modification ofBOPE components necessary for drilling geothermalwells.

Section 5 outlines inspection and testing procedures forall components of the BOPE array, except the hole-fluidmonitoring system. These procedures may be modifiedin the field by a division inspector to conform to currentpolicy, but complete testing may be ordered if the appar-ent condition of the BOPE is such that a question exists asto the ability of the components to function satisfactorily.

During the preparation of this manual, personnel wereconsulted from oil, gas, and geothermal operating com-panies, equipment manufacturing firms, service compa-nies, petroleum consulting firms, and industry organiza-tions, and many of their suggestions are included. Muchmaterial is based on industry and trade publications,particularly the specifications and recommended prac-tices of the American Petroleum Institute (API).

Section 3219, Division 3, of the Public Resources Code(PRC) of the State of California states, in part, thatoperators must equip wells...”with casings of sufficientstrength, and with such other safety devices as may benecessary, in accordance with methods approved by thesupervisor, and shall use every effort and endeavoreffectually to prevent blowouts, explosions, and fires”.Additional requirements for casing and blowout pre-vention equipment (BOPE) are provided by several sec-tions of Title 14 of the California Code of Regulations,particularly Section 1722.5, which establishes this manualas the guide for engineers of the Department of Conser-vation, Division of Oil, Gas, and GeothermalResources...”in establishing the blowout preventionequipment requirements specified in the division’s ap-proval of proposed operations”.

Besides serving as a guide for Division of Oil, Gas, andGeothermal Resources (division) engineers, the manualis designed to help operator personnel in planning theirwell operations. By serving as a single-source guide toblowout prevention equipment (BOPE) used in oil, gas,and geothermal operations in California, the manualwill help operators conform to the BOPE requirements ofthe Public Resources Code and the California Code ofRegulations.

The manual is oriented primarily toward the equipmentinvolved in blowout prevention. Therefore, severalimportant aspects of kick control and blowout preven-tion practices, such as casing programs, kick-controlprocedures, and crew training are discussed only briefly,if at all. This does not mean that the division placesreduced emphasis on these aspects of blowout preven-tion. In fact, Section 1722(c), Title 14, California Code ofRegulations requires that “For certain critical or high-pressure wells designated by the supervisor, a blowoutprevention and control plan, including provisions forthe duties, training, supervision, and schedules for test-ing equipment and performing personnel drills, shall besubmitted by the operator to the appropriate divisiondistrict deputy for approval”. Once approved, a copy ofthe plan must be available at each well site for use by theoperator and contractor personnel for training rig crews.The plan is also used by division inspectors when evalu-ating blowout prevention (BOP) preparedness. For criti-cal or high-pressure wells, the division may elect towitness one or more of the required weekly blowoutdrills in the company of the operator’s representative orcontractor’s foreman. (Division engineers are not autho-

2 DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES

modify the BOPE to handle any anticipated de-mands or to bring it into conformance with currentAPI specifications and arrangements.

e. The stack arrangements, depicted in Figures 1through 6 of this section, are for illustrative purposesonly. The operator may use any desired arrange-ment of preventers and drilling spools, provided thetotal system meets the BOPE classification assignedby the division and provisions have been made tocontrol the well under any predictable conditions.

f. The following BOP stack component codes, as usedin paragraphs 2-2c and 2-2d and in Figs. 1 through 6of this manual, are taken from API RP 53: BlowoutPrevention Equipment for Drilling Wells. The codesare:

A = annular-type blowout preventer.

G = rotating head.

R = single ram-type preventer with one set oframs.

Rd = double ram-type preventer with two sets oframs.

Rt = triple ram-type preventer with three sets oframs.

S = drilling spool with side outlet connections forchoke and kill lines.

M = 1,000 psi rated working pressure.

Components are listed from the bottom componentto the top component, that is from the uppermostpiece of permanent wellhead equipment or the bot-tom of the preventer stack.

g. If conditions warrant, the division may approve theinstallation of a diverter system when a well is to bedrilled to a shallow total depth. However, in areaswhere steam injection or other sources of shallowoverpressure might present a threat of blowout, thedivision may require an operator to install a diverter

2 - 1 GENERAL

a. The classification and selection system describedin this section is used by the Division of Oil, Gas,and Geothermal Resources to arrive at uniformrequirements for blowout prevention equipmentin California. Each proposed program of welloperations is reviewed by a division engineerand, if warranted by the operation, one or moreBOPE classifications are assigned. These classifi-cations are based on accepted engineering prac-tices based on the proposed operations, surfaceenvironment, geological conditions, and knownor anticipated subsurface pressures.

b. A complete BOPE classification (e.g., Class III B3M) is composed of three elements that identify,respectively, the division’s requirements for blow-out prevention equipment, hole-fluid monitoringequipment, and rated working pressure of the weak-est component of the wellhead stack and chokesystem. In this example, the well is to be equippedwith Class III BOPE, as outlined in paragraph 2-2dand a Class B hole-fluid monitoring system, as out-lined in paragraph 2-3b. The equipment must havea rated working pressure minimum of 3,000 psi(3M). The three elements may be assigned in anycombination that will provide adequate blowoutprotection.

Table 1, is provided as a quick guide to BOPE classi-fication (shown in box d) that will probably berequired by the division for any well, given theproposed operation (box a), the well environment(box b), and the anticipated surface pressure (box c).

c. Each proposed well operation will be considered inits entirety by a division engineer before BOPE clas-sifications are assigned. More than one BOPE clas-sification will be assigned if warranted by differentstages of the proposed casing program. Theclassification(s) will be specified on the division’sPermit to Conduct Well Operations (Form OG 111).

d. Paragraph 2-2 describes the minimum equipmentfor each class of BOPE. Additional requirementsmay be specified, on an individual well basis, to

2. CLASSIFICATION AND SELECTION OFEQUIPMENT


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system on shallow casing strings before it becomespracticable to install one of the regular classes ofBOPE, as described in paragraph 2-2. If a divertersystem is required by the division, it must be de-signed to direct the flow of well fluids away from theworking area of the rig, and away from public roads,buildings, or sensitive environments in the immedi-ate area. The crew must be trained in the use of thesystem.

Proper installation and use of a diverter system willminimize the possibility of the crew shutting in thewell completely when this might damage forma-tions that would be exposed to annulus pressures.This will protect against formation fracture thatcould cause an underground blowout (the escape ofhole fluid through the walls of the hole), which couldcause injury or loss of life, property loss, and/or lossof natural resources.

2-2 CLASSIFICATION OF BLOWOUT PREVENTION EQUIPMENT

a. A diverter system, when required, must be installedon the conductor casing, drive pipe, or first surfacecasing before drilling out the shoe of that string ofcasing, and must be maintained in good workingorder until an adequate BOPE anchor string hasbeen cemented in the hole and the required BOPEsystem has been installed.

The well crew must be trained in the use of thediverter system and a weekly diverter drill held foreach crew. Records of the drills must be entered inthe daily log book.

The diverter system will contain, as a minimum, thefollowing components:

1. Either a special purpose annular preventer, de-signed specifically as a diverter, with an outletbelow the packing element that opens automati-cally as the diverter is closed, or a regular annu-lar preventer with special attention to the valvingand venting requirements listed in paragraphs2-2a2 and 2-2a3, which follow.

2. A six-inch (onshore drilling wells) or eight-inch(offshore drilling wells) minimum ID outlet be-low the diverter, equipped with a full-openinggate, ball, plug, or butterfly valve or an easilybroken (frangible) diaphragm that will preventthe flow of wellbore fluids through the lineduring normal operations, but which opens au-tomatically or may be quickly and easily openedmanually before-or-as the diverter is closed.

As an alternative to this valve, the system maybe designed as an open flow system as depictedin Figure 13A of this manual and in the illustra-tions accompanying Section 2-A, API RP 53 (seeSelected References).

For a rework operation in which side openingson the existing wellhead are smaller than 6inches ID, a mud cross with 6-inch outlets mustbe installed between the wellhead and thediverter. If the operator intends to install a ventline(s) smaller than 6 inches to the side opening(s)of the wellhead, permission to do so must beobtained from the division engineer who evalu-ates the proposal, and the 6-inch requirementmust be waived on the Permit to Conduct WellOperations, form OG111.

3. A diverter vent system of the same minimum IDas the diverter outlets that fulfills the followingrequirements:

a) For onshore wells, a single vent line may beinstalled. This line must terminate in asump or other suitable receptacle at a loca-tion from which it is unlikely that effluentfrom the vent line will be blown or carriedtoward the rig or toward any building, pub-lic road, or sensitive environment in theimmediate area.

b) For offshore wells, multiple vent lines mustbe installed, with a selector valve systemthat will permit the crew to select the down-wind line or the gas stack.

c) Vent lines must be as straight as practicable,with any necessary turns targeted as de-scribed in paragraphs 3-4a7. The line(s)must be anchored securely to prevent whip-ping or vibration damage, and no sleeve-type couplings may be used.

b. A Class I BOPE system consists of, as a minimum,any device installed at the surface that is capable ofcomplete closure of the well bore with the pipe outof the hole. The device must be closed whenever thewell is unattended. See paragraph 3-2a1 for addi-tional requirements if an annular preventer is usedas the closing device.

c. A Class II BOPE system (API arrangements A, Rd,RR, or RA) consists of, as a minimum, the followingcomponents:

1. Annular and/or ram-type preventers capable ofproviding complete closure of the well bore, and


fig. 1

* For workover operations not requiring a drilling-typecirculating system, requirements 4, 5, and 7 do not apply.

closure around the pipe in use. See paragraph 3-2a1 for additional requirements if an annularpreventer is used alone (API arrangement A).

2. Manual closing devices, unless a remote actuat-ing system is specified.

3. Access line of 2-inch minimum outside diam-eter into the well bore below the preventer(s),with suitable valves and fittings for pressurerelief or well killing operations.

4. Fill-up line into the bell nipple above thepreventer stack, but not in direct line with theflow line.*

5. Kelly cock or standpipe valve.*

6. Full-opening safety valve readily available onthe rig floor, in the open position, with fittingsadaptable to all pipe to be used in the proposedoperations. If this valve is of the type that ismade up into the working string, it must fitthrough the wellhead equipment in use.

7. Internal preventer inside the pipe in use, orreadily available at the rig in the open position,with fittings adaptable to the safety valve re-quired by 2-2c6. This valve must fit through thewellhead equipment in use and must be storedin such a position or identified in such a mannerthat it will not be the first valve installed by thecrew in response to a kick taken while trippingpipe.*


fig 2

pipe, which are to be used in the proposedoperations. All ram-type preventers must haveindependent, positive-locking devices.

2. An actuating system with the primary source ofenergy (usually the accumulator unit) located atleast 50 feet from the well bore. The actuatingsystem must be capable of accomplishing ALLof the following actions within two minuteswith the source of power to any charging pump(s)disconnected:

a) Close and open one ram-type preventer;

b) Close the annular preventer on the smallest-diameter pipe for which pipe rams havebeen installed;

c) Perform all immediate kick-control re-sponses involving any installed auxiliaryequipment for which this actuating systemserves as the source of energy.

For preventers with very large operating vol-umes, the two-minute time limit may be ex-tended to cover the time during which fluid ismoving continuously in the system to performthis sequence of actions.

If the actuating system is of the hydropneumatictype, it must contain enough USABLE FLUID toaccomplish actions a), b), and c) just discussedwith the source of power to the accumulatorpump disconnected.

NOTE: USABLE FLUID is defined as the vol-ume of fluid that may be withdrawn from theaccumulator(s) without lowering the pressurein the actuating system below 1,000 psi, or 200psi above the manufacturer’s recommendedaccumulator precharge pressure, whichever isgreater. The value of 1,000 psi is selected as theminimum acceptable pressure because it ap-proximates the pressure required to hold anannular preventer closed on open hole.

In addition, an emergency backup system mustbe installed at the source of energy for the actu-ating system. The backup system must containenough usable fluid, or enough usable fluidequivalent, to close the annular preventer onopen hole and open any installed remote-con-trolled valves on the choke line. The backupsystem must utilize an independent, explosion-safe source of actuating energy.

d. A Class III BOPE system (API arrangements SRdA,SRRA, or RSRA) consists of, as a minimum, thefollowing components:

1. Annular preventer, blind (CSO) ram-typepreventer, and pipe ram-type preventer(s) ca-pable of closure around all pipe, exclusive ofdrill collars and short “stinger” strings of smaller


fig 3


fig 4


3. Dual control stations: one within 10 feet of thedriller’s station if the configuration of the drill-ing floor permits (preferably on the nearest exitroute from the rig floor), and the other at theactuating system.

4. Kill line of 2-inch minimum outside diameter,containing at least one control valve, one checkvalve, and fittings for an auxiliary pump con-nection. See paragraph 3-4b for specific require-ments. The kill line should enter the well borebeneath one set of pipe rams, with an optionalauxiliary connection below the lowermost rams.

5. Choke system containing at least one controlvalve, one adjustable choke, a bleed line, and anaccurate pressure gauge. See paragraph 3-4a forspecific requirements. Normally, the choke lineoutlet from the well bore will be located beneathone set of pipe rams. However, if the operator’sBOPE guidance recommends that the pipe ramsbe placed in a “master gate” position at the baseof the BOPE stack (API arrangement RSRA), thedivision will approve the placement of the chokeline outlet between the pipe rams and the CSOrams with the provision that the operator main-tains an extra set of pipe rams at the well site toexchange for the CSO rams if a kick is taken withpipe in the hole. The division will not approveplacement of the choke line outlet above all ofthe ram preventers. In offshore and criticalonshore areas, the choke line must dischargeinto existing production facilities or a suitablecontainer.

6. Kelly cock, standpipe valve, and standpipe pres-sure gauge.*


8. Full-opening safety valve, readily available onthe rig floor in the open position, with fittingsadaptable to all pipe to be used in the proposedoperations. If this valve is of the type that ismade up into the working string, it must fitthrough the wellhead equipment in use.

9. Internal preventer inside the pipe in use, orreadily available on the rig floor in the openposition, with fittings adaptable to the safetyvalve required by 2-2d8. This valve must fit

through the wellhead equipment in use andmust be stored in such a position, or identified insuch a manner, that it will not be the first valveinstalled by the crew in response to a kick takenwhile tripping pipe.*

e. A Class IV system consists of, as a minimum, thefollowing components:

1. Annular preventer, blind (CSO) ram-typepreventer, and two or more pipe ram-typepreventer(s) capable of closure around all pipe,exclusive of drill collars and short “stinger”strings of smaller pipe, to be used in the pro-posed operations. The blind rams must be aboveat least one set of pipe rams. All ram-typepreventers must have independent, positive-locking devices.

2. An actuating system with the primary source ofenergy (usually the accumulator unit) located atleast 50 feet from the well bore. The actuatingsystem must be capable of accomplishing ALLof the following actions within two minuteswith the source of power to any charging pump(s)disconnected:

a) Close and open one ram-type preventer;

b) Close the annular preventer on the smallest-diameter pipe for which pipe rams havebeen installed;

c) Perform all immediate kick-control re-sponses involving any installed auxiliaryequipment for which this actuating systemserves as the source of energy.

For preventers with very large operating vol-umes, the two-minute time limit may be ex-tended to cover the period of time during whichfluid is moving continuously in the system toperform this sequence of actions.

If the actuating system is of the hydropneumatictype, it must contain enough USABLE FLUID toaccomplish a), b), and c) just discussed with thesource of power to the accumulator pump dis-connected.

NOTE: USABLE FLUID is defined as the vol-ume of fluid that may be withdrawn from theaccumulator(s) without lowering the pressurein the actuating system below 1,000 psi, or 200psi above the manufacturer’s recommended* For workover operations not requiring a drilling-type

circulating system, requirements 6, 7, and 9 do not apply.


fig 5


accumulator precharge pressure, whichever isgreater. The value of 1,000 psi is selected as theminimum acceptable pressure because it ap-proximates the pressure required to hold anannular preventer closed on open hole.

In addition, an emergency backup system mustbe installed at the source of energy for the actu-ating system. The backup system must containenough usable fluid, or enough usable fluidequivalent, to close the annular preventer onopen hole and open any installed remote-con-trolled valves on the choke line. The backupsystem must utilize an independent, explosion-safe source of actuating energy.

3. Dual control stations: one within 10 feet of thedriller’s station if the configuration of the drill-ing floor permits, (preferably on the nearest exitroute from the rig floor), and the other at theactuating system.

4. Kill line of 2-inch minimum outside diameter,containing at least one control valve, one checkvalve, and fittings for an auxiliary pump con-nection. See paragraph 3-4b for specific require-ments. The kill line should enter the well borebeneath one set of pipe rams, with an optionalauxiliary connection below the lowermostpreventer.

5. Choke system containing at least one controlvalve, two adjustable chokes, a bleed line, andan accurate pressure gauge. See paragraph 3-4afor specific requirements. The choke line outletfrom the well bore should be located above oneset of pipe rams, with an optional auxiliaryconnection below the lowermost preventer. Inoffshore and critical onshore areas, the chokeline must discharge into existing productionfacilities or a suitable container.

6. Upper and lower kelly cocks installed in thekelly at all times. See paragraph 3-5c for kellycock requirements when using a downhole mudmotor or a top drive system.*

7. Standpipe valve, and standpipe pressure gauge.*


9. Full-opening safety valve, readily available on

the rig floor in the open position, with fittingsadaptable to all pipe to be used in the proposedoperations. If this valve is of the type that ismade up into the working string, it must fitthrough the wellhead equipment in use.

10. Internal preventer inside the pipe in use, orreadily available on the rig floor in the openposition, with fittings adaptable to the safetyvalve required by 2-2e9. This valve must fitthrough the wellhead equipment in use andmust be stored in such a position, or identified insuch a manner, that it will not be the first valveinstalled by the crew in response to a kick takenwhile tripping pipe.*

f. A Class V BOPE system applies only in the case ofa subsea BOPE stack (see paragraph 3A-3 for re-quirements and Figure 6 for BOP stack configura-tion).

2-3 CLASSIFICATION OF HOLE-FLUID MONITORING EQUIPMENT

a. Class A - Any device capable of a reasonably accu-rate determination of mud system gains and losses.

b. Class B

1. Mud pit level indicator with audible alarm.

2. Any device, such as a pump stroke counter, triptank, etc., capable of a reasonably accurate de-termination of the volume of fluid required tokeep the hole full when pulling pipe.

c. Class C

1. A recording mud pit level indicator or pit vol-ume totalizer system to determine mud pit vol-ume gains and losses. This indicator must in-clude both visual and audible warning devices.

2. A mud volume measuring device capable ofaccurately determining the mud volume neces-sary to keep the hole full when pulling pipe fromthe hole.

3. A mud return or full-hole indicator to showwhen returns have been obtained, or when theyoccur unintentionally, and that returns essen-tially equal the pump discharge rate.

If slim hole operations are anticipated, the mudreturn indicator should be of an electromag-

* For workover operations not requiring a drilling-typecirculating system, requirements 6, 7, 8, and 10 do not apply.


fig 6


netic or impulse design because of their in-creased sensitivity and accuracy, rather than thecustomary paddle-type flow line indicator.

4. Gas-detection equipment to monitor the drill-ing mud returns for hydrocarbons and hydro-gen sulfide (H2S) at critical locations along themud system.

2-4 SELECTION OF BOPE AND HOLE-FLUID MONITORING EQUIPMENT

The classification system outlined in paragraphs 2-2 and2-3 is applied by the division to each proposed well so therequired equipment will provide an adequate margin ofsafety. Table 1, Guidelines for Selection of BOPE andHole-Fluid Monitoring Equipment, is intended to assistselection in areas where field rules do not apply.

EXAMPLE:

An operator proposes to sidetrack a bad liner in a welllocated in a residential area. There are no flowing wellsin the field. The zone pressure is 800 psi and the oilgravity is 19o API. The depth to the top of the zone is3,600 feet. What class of equipment should be used?

SOLUTION:

Well Conditions

Proposed well operations: Redrill-development

Well environment: Onshore critical

Anticipated surface pressure: Medium pressure

From Table 1: Class III B equipment should be used.

2-5 SELECTION OF PRESSURE RATING

Two separate pressures may have to be consideredbefore selecting the pressure rating portion of a BOPEclassification, one for a final pressure determination andanother if an interim determination is requested.

a. The Maximum Predicted Casing Pressure (MPCP)is the basis for the selection of a final BOPE pressurerating. The MPCP is the maximum known or esti-mated bottom-hole pressure (BHP) at total depth,minus the back pressure exerted by a column of gasextending from total depth to the surface. In areas

where no zone pressure data are available, an ac-ceptable BHP may be estimated by multiplying theproposed total vertical depth by a normal formationpressure gradient of 0.465 psi/foot. The BHP maythen be multiplied by the MPCP/BHP ratio for thatdepth (Fig. 7) to obtain a MPCP for the hole. Thispressure condition would occur if all liquids wereremoved from the hole due to gas entry or lostcirculation and would place the greatest demand onthe BOPE.

b. The Maximum Allowable Casing Pressure (MACP)is the basis for selection of an interim BOPE pressurerating.

For a drilling well containing hole fluid of a givendensity, the MACP is the surface pressure that wouldbe likely to fracture the formation immediately be-low the shoe of the BOPE anchor string or ruptureany casing string subjected to that pressure.

For a workover, the MACP is usually determined bythe density of the workover fluid and the depth toopen perforations or, occasionally, the minimuminternal yield pressure of the BOPE anchor string ofcasing. See Appendix E for an explanation of therelationship between the MACP applied againstopen hole and the MACP applied through perfo-rated casing.

In either case, the MACP must be recalculated when-ever additional casing is cemented and when thehole-fluid density is changed significantly. Thispressure will be the lesser of the following twopressures:

1. Formation Fracture Pressure - the surface pres-sure that, when added to the hydrostatic pres-sure exerted by the column of fluid in a hole,could reasonably be expected to fracture theformation at the shoe of the anchor string or atthe perforations, whichever occurs higher in thehole. A value for this pressure may be approxi-mated from Figure 8. A more accurate fracturepressure may be obtained by performing aleakoff test of the exposed formation.

2. Casing Yield Pressure - the surface pressurethat, when added to the hydrostatic pressureexerted by the column of hole fluid at any depth,would result in an overbalance (with respect tothe pressure behind the casing at that depth) thatexceeds the minimum internal yield strength ofthat casing as listed in Appendix D.


SAMPLE PROBLEM FOR DETERMINING THEBOPE PRESSURE RATING

An operator proposes to reperforate the producing zonein a well for which the BOPE requirement has beendetermined to be Class II. The operator provides thefollowing information concerning the well:

8-5/8", 32#, J-55 casing cemented at 4,000'.

5-1/2", 17#, J-55 liner cemented from 3,960' to 4,500'.

Water shut-off (WSO) on 5-1/2" x 8-5/8" lap.

Liner perforated from 4,400' to 4,500'.

Total depth: 4,500'.

Producing clean, 38o API gravity oil (sp. gr. 0.835).

Static fluid level at 1,500' below surface.

Shut-in casing pressure: 50 psig.

Proposed workover fluid weight: 73.5 pcf.

Formation pressure gradient : 0.465 psi/ft.

SOLUTION:

STEP 1. Determine the Maximum Predicted CasingPressure (MPCP) as follows:

a. Calculate the BHP by using fluid level, pressuregradient, and shut-in casing pressure informationand the following formulas. (Pressure gradient ofthe produced fluid x height of the fluid column) +shut-in casing pressure.

The pressure gradient of the produced fluid is theproduct of the specific gravity of the produced fluidand the pressure gradient of fresh water.

Therefore, BHP = [(0.835 x 0.433)(4,500 - 1,500)] + 50= 1,135 psi

b. From Figure 7, obtain the MPCP/BHP ratio for thetotal depth and multiply by the BHP to obtain theMPCP.

The MPCP/BHP for a TD of 4,500'= 0.91MPCP = 0.91 x 1,135 = 1,033 psi.

STEP 2. Calculate the Maximum Allowable CasingPressure (MACP) for the existing hole conditions.

a. Obtain the Formation Fracture Pressure from Figure8 as follows:

1) Enter the chart from the left margin at the depthof the exposed formation (i.e., top perfs, at 4,400').

2) Move to an interpolated point (between 70 pcfand 80 pcf fluid curves) that would represent theproposed workover fluid weight (73.5 pcf).

3) Move to the upper margin to obtain the pressureapplied through the perfs.

4) Read the Formation Fracture Pressure (1,450psi).

NOTE: If the liner in this example had been installedwith a hanger instead of being cemented in place, theformation would be exposed to well pressure at theshoe of the 8-5/8" casing at 4,000'. In this case, thelower margin of the graph (Fig. 8) would haveapplied, and the Formation Fracture Pressure wouldhave been 960 psi.

b. Calculate the Casing Yield Pressure for the anchorstring of casing as follows:

1) Calculate the pressure gradient of the proposedworkover fluid using the factor 0.0069 (i.e., 0.433/ 62.4) to convert fluid weight in pcf to pressuregradient. 73.5 x 0.0069 = 0.510 psi/ft.

2) Calculate the overbalance gradient with respectto the formation pressure gradient by multiply-ing the pressure gradient of the proposedworkover fluid by the formation pressure gradi-ent. 0.510 - 0.465 = 0.045 psi/ft.

3) Calculate the overpressure at the top of the linerlap by multiplying the overbalance gradient bythe depth to the liner top. 3,960 x 0.045 = 178 psi.

4) Subtract the overpressure from the minimuminternal yield pressure of the anchor string usingAppendix D to obtain the casing yield pressure.For 8-5/8" 32# J-55 casing, the minimum inter-nal yield pressure is 3,930 psi.

Casing Yield Pressure= 3,930 - 178 = 3,752 psi

NOTE: For a well in which the anchor string is madeup of several grades of casing, or in areas where auniform formation pressure gradient does not applyfrom surface to total depth, the casing yield pressuremay have to be calculated for several points in thehole to determine a minimum value for the well.


fig 7


PROCEDURE FOR USE OF FIGURE 815

fig 8

MAXIMUM ALLOWABLE SURFACE PRESSURE (MACP) vs. DEPTH AND ASSUMEDFRACTURE GRADIENT

FIGURE 8

ASSUMPTIONS: 1. Formation pressure is 0.465 psi/foot at all depths.

2. Fracture gradient behaves accordingto Cristman.14

In areas where these assumptions are known to be invalid,the MACP as determined from the graph must be multipliedby one or both of the following factors, as applicable:

1. Known fracture gradient

Fracture gradient from right margin of graph

and/or

2. Known formation pressure

0.465 x depth

INSTRUCTIONS: 1. Enter the graph from the left mar-gin at the depth to the shoe of theBOPE anchor string or the top of theproduction perfs., as applicable.

2. Move horizontally to a point cor-responding to the density of the fluidto be used during the proposed opera-tions. Interpolate if necessary.

3. Move vertically from that pointto the lower margin if there is to beopen hole below the shoe of the BOPEanchor string. Move to the upper mar-gin if the pressure is to be applied toexisting production perforations in afully cased hole (see Appendix E).

15 Superior figures refer to the list of Selected References at the end of the report.


c. The MACP for existing hole conditions is the lesserof the amounts in Step 2, a.4 and b.4 of this solution.In this case, the MACP is the formation fracturepressure of 1,450 psi.

STEP 3. The minimum final working pressure rating forthe BOPE is 1,033 psi (the MPCP from Step 1 of thissolution). The lowest rated working pressure ratingcommonly available in BOP equipment is 2,000 psi;therefore, the BOPE classification would be Class II 2M.In this case, there is no requirement for hole-fluid moni-toring equipment. The MACP that should be brought tothe attention of the rig crew is 1,450 psi. It is unlikely thatthe surface pressure would reach that value, since theMPCP is only 1,033 psi.

2-6 ADDITIONAL REQUIREMENTS

The following requirements are mandatory for all opera-tions conducted on offshore, onshore critical, or high-pressure areas.

a. All required BOPE must be inspected and, if appli-cable, actuated periodically to ensure operationalreadiness. The minimum frequency of this inspec-tion/actuation is as follows:

1. At least once during each eight-hour tour, thefollowing are to be performed:

a) Check accumulator pressure.

b) Check emergency backup system pressure.

c) Check hydraulic fluid level in accumulatorunit reservoir.

d) Actuate all audible and visual indicatorsand alarms.

2. On each trip, but not more often than once each24-hour period, the following are to be actuated:

a) Pipe rams (before starting out of the hole).

b) Blind (CSO) rams (after pulling the pipefrom the hole).

c) All installed kelly cocks.

d) Drill pipe safety valve.

e) Internal preventer.

f) Adjustable chokes.

g) Hydraulic valves, if any.

3. Once each seven days, the following are to beactuated:

a) The annular preventer on drill pipe or tub-ing.

b) All gate valves in the choke and kill systems.

c) All manually operated BOP locking devices.

b. BOPE practice drills and training sessions must beconducted at least once each week for each crew.These drills may be performed in conjunction withthe operational readiness tests outlined in para-graph 2-6a, and must provide training for each mem-ber of the crew to ensure (as a minimum):

1. A clear understanding of the purpose and themethod of operation of each preventer and allassociated equipment.

2. The ability to recognize the warning signs thataccompany a kick.

If the proposed work involves any slim holeoperations, the crew must be alerted to the factthat the warning signs of a kick can develop veryrapidly during slim hole operations because ofthe reduced volume of the annulus. The crewmust be continuously alert to any kick signssuch as changes in pit volume or hole-fluid flowrate, changes in the physical properties of thehole fluid, and unexplained changes in the drill-ing rate and/or the pump pressure.

3. A clear understanding of each crew member’sstation and duties in the event of a kick whiledrilling, while tripping pipe, while drill collarsare in the preventers, and while out of the hole.

4. A clear understanding of the maximum allow-able casing pressure (MACP) and the signifi-cance of the pressure for well conditions thatexist at the time of the drill or training session.

c. A record of all inspections, tests, crew drills, andtraining sessions must be kept in the daily log book.

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