-
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
iii
1222222222444469
11111111111313131317171717
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
iv
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
v
SECTION PARAGRAPH PAGE666767676868686868686969707171
7171
7575
7878787885
8585858585
8594949495959596
-
vi
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
-
3BLOWOUT PREVENTION IN CALIFORNIA
Tabl
e 1.
Gui
delin
es fo
r sel
ectio
n of
BO
PE
and
hol
e flu
id m
onito
ring
equi
pmen
t.
-
4 DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES
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
-
5BLOWOUT PREVENTION IN CALIFORNIA
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.*
-
6 DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES
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
-
7BLOWOUT PREVENTION IN CALIFORNIA
fig 3
-
8 DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES
fig 4
-
9BLOWOUT PREVENTION IN CALIFORNIA
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.*
7. Fill-up line into the bell nipple above thepreventer stack,
but not in direct line with theflow line.*
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.
-
10 DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES
fig 5
-
11BLOWOUT PREVENTION IN CALIFORNIA
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.*
8. Fill-up line into the bell nipple above thepreventer stack,
but not in direct line with theflow line.*
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.
-
12 DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES
fig 6
-
13BLOWOUT PREVENTION IN CALIFORNIA
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.
-
14 DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES
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.
-
15BLOWOUT PREVENTION IN CALIFORNIA
fig 7
-
16 DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES
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.
-
17BLOWOUT PREVENTION IN CALIFORNIA
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.