Well Control Equipment Systems for
Drilling Wells
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API STANDARD 53
FIFTH EDITION, DECEMBER 2018
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Special Notes
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guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or
damage resulting from its use or for the violation of any authorities having jurisdiction with which this publication may
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API publications are published to facilitate the broad availability of proven, sound engineering and operating
practices. These publications are not intended to obviate the need for applying sound engineering judgment
regarding when and where these publications should be utilized. The formulation and publication of API publications
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scientific, engineering, and safety judgment should be used in employing the information contained herein.
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Foreword
Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the
manufacture, sale, or use of any method, apparatus, or product covered by letters patent. Neither should anything
contained in the publication be construed as insuring anyone against liability for infringement of letters patent.
The verbal forms used to express the provisions in this specification are as follows:
— the term “shall” denotes a minimum requirement in order to conform to the standard;
— the term “should” denotes a recommendation or that which is advised but not required in order to conform to the
standard;
— the term “may” denotes a course of action permissible within the limits of a standard;
— the term “can” is used to express possibility or capability.
This document was produced under API standardization procedures that ensure appropriate notification and
participation in the developmental process and is designated as an API standard. Questions concerning the
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Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A one-time
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Suggested revisions are invited and should be submitted to the Standards Department, API, 1220 L Street, NW,
Washington, DC 20005, standards@api.org.
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iii
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Contents
Page
1
Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2
Normative References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
3
3.1
3.2
4
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Terms, Definitions, and Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Terms and Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Well Control Equipment General Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
BOP Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Choke and Kill Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
BOP Control Systems (Land, Surface Offshore, Subsea) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Auxiliary Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
System Pressure Sealing Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
BOP Preventers for H2S Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Pressure Measurement Devices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
5
5.1
5.2
5.3
5.4
Surface BOP Systems (Land and Surface Offshore) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Surface BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Choke Manifolds, Choke Lines, and Kill Lines-Surface BOP Installations . . . . . . . . . . . . . . . . . . . . . . 27
Testing-Surface BOP Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Inspection and Maintenance-Surface BOP Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
6
6.1
6.2
6.3
6.4
6.5
Subsea BOP Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Subsea BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Choke Manifolds, Choke Lines, and Kill Lines-Subsea BOP Installations . . . . . . . . . . . . . . . . . . . . . . 41
BOP Control Systems (Subsea). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
Testing-Subsea BOP Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
Inspection and Maintenance-Subsea BOP Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Annex A (normative) Accumulator Pre-charge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
Annex B (informative) Example Worksheets and Calculations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Annex C (normative) Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Annex D (normative) Failure Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
Figures
1
Example Land and Surface Offshore BOP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
2
Example 2K and 3K RWP Choke Line and Choke Manifold for Land and Surface Offshore . . . . . . . . . . 28
3
Example 5K RWP Choke Line and Choke Manifold for Land
Example 5K Choke Line and Choke Manifold for Surface Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
4
Example 10K RWP or Greater Choke Line and Choke Manifold for Land
Example 10K RWP or Greater Choke Line and Choke Manifold for Surface Offshore . . . . . . . . . . . . . 29
5
Example 2K RWP Kill Line for Land and Surface Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
6
Example 3K or Greater RWP Kill Line for Land and Surface Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
7
Example 3K or Greater RWP Kill Line for Land and Surface Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
8
Example Subsea BOP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
9
Example Subsea Choke Manifold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
B.1 Example BOP Function Test Worksheet for Land and Surface Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . 54
B.2 Example BOP Drawdown Test Worksheet for Land and Surface Offshore . . . . . . . . . . . . . . . . . . . . . . . . 55
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Contents
Page
B.3 Example BOP Function Test Worksheet for Subsea. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
B.4 Example BOP Function Test Worksheet for Subsea. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Tables
1
Surface BOP Pressure Designations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
2
Subsea BOP Pressure Designations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
B.1 Example Surface MEWSP Calculations Given Well and Equipment-specific Data . . . . . . . . . . . . . . . . . . 58
B.2 Example Subsea MEWSP Calculations Given Well and Equipment-specific Data . . . . . . . . . . . . . . . . . . 58
C.1 Initial Function Testing, Surface BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
C.2 Subsequent Operational Function Testing, Surface BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
C.3 Scheduled Function Testing, Surface BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
C.4 Initial Pressure Testing, Surface BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62
C.5 Subsequent Operational Pressure Testing, Surface BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
C.6 Operating Chamber Pressure Testing, Surface BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
C.7 Pre-deployment Function Testing, Subsea BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
C.8 Initial Function Testing, Subsea BOP Stacks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67
C.9 Subsequent Operational Function Testing, Subsea BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68
C.10 Scheduled Function Testing, Subsea BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69
C.11 Pre-deployment Pressure Testing, Subsea BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70
C.12 Initial Pressure Testing, Subsea BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
C.13 Subsequent Operational Pressure Testing, Subsea BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
C.14 Operating Chamber Pressure Testing, Subsea BOP Stacks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
vi
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Introduction
This standard represents a composite of the practices employed by various operating and drilling companies in
drilling operations. This standard is under the jurisdiction of the API Committee on Standardization of Oilfield
Equipment and Materials.
The objective of this standard and the recommendations within is to assist the oil and gas industry in promoting
personnel safety, public safety, integrity of the drilling equipment, and preservation of the environment for land and
marine drilling operations. In the context of blowout prevention systems, this objective is best attained through a
combination of equipment reliability and management of risk. This standard is published to facilitate the broad
availability of proven, sound engineering and operating practices that meet the stated objective through practices that
improve reliability and reduce risk to acceptable levels. This standard does not present all of the operating practices
that can be employed to successfully install and operate blowout preventer systems in drilling, completions, and well
testing operations. Practices set forth herein are considered acceptable for accomplishing the job as described;
however, equivalent alternative installations and practices can be used to accomplish the same objectives. Individuals
and organizations using this standard are cautioned that operations must comply with requirements of federal, state,
or local regulations. These requirements should be reviewed to determine whether violations can occur.
The First Edition of API 53, published in February 1976, superseded API Bulletin D13, Installation and Use of Blowout
Preventer Stacks and Accessory Equipment, February 1966. The Second Edition of API 53 was issued in May 1984,
the Third Edition of API 53 was issued in March 1997 and the Fourth Edition of API 53 was issued in November 2012.
This edition supersedes all previous editions of this standard.
Drilling operations are being conducted with full regard for personnel safety, public safety, and preservation of the
environment in such diverse conditions as metropolitan sites, wilderness areas, ocean platforms, deepwater sites,
barren deserts, wildlife refuges, and arctic ice packs. The information presented in this standard is based on this
extensive and wide-ranging industry experience.
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Well Control Equipment Systems for Drilling Wells
1
Scope
The purpose of this standard is to provide requirements for the installation and testing of blowout prevention
equipment systems on land and marine drilling rigs (barge, platform, bottom-supported, and floating).
Well control equipment systems are designed with components that provide wellbore pressure control in support of
well operations. The following components may be used for operation under varying rig and well conditions:
― BOPs (blowout preventers);
― Choke and kill lines;
― Choke manifolds;
― Control systems;
― Auxiliary equipment.
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The primary functions of these systems are to confine well fluids to the wellbore, provide means to add fluid to the
wellbore, and allow controlled volumes to be removed from the wellbore.
Diverters, shut-in devices, and rotating head systems (rotating control devices) are not addressed in this standard
(see API 64 and API 16RCD, respectively); their primary purpose is to safely divert or direct flow rather than to
confine fluids to the wellbore.
Procedures and techniques for well control are not included in this standard because they are beyond the scope of
the equipment systems contained herein.
This standard contains a section pertaining to surface BOP installations followed by a section pertaining to subsea
BOP installations.
To the extent that this document recommends specific equipment arrangements, it is recognized that other
arrangements can be equally effective in addressing well requirements and achieving safety and operational
efficiency.
2
Normative Reference
The following referenced documents are indispensable for the application of this document. For dated references,
only the edition cited applies. For undated references, the latest edition of the referenced document applies
(including any addenda/errata).
API Specification 6A, Specification for Wellhead and Tree Equipment
API Specification 16A, Specification for Drill-through Equipment
API Standard 16AR, Standard for Repair and Remanufacture of Drill-through Equipment
API Specification 16C, Choke and Kill Equipment
API Specification 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems
for Diverter Equipment
1
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2
API STANDARD 53
API Recommended Practice 17H, Remotely Operated Tools and Interfaces on Subsea Production Systems
API Recommended Practice 500, Recommended Practice for Classification of Locations for Electrical Installations
at Petroleum Facilities Classified as Class I, Division 1 and Division 2
API Recommended Practice 505, Recommended Practice for Classification of Locations for Electrical Installations
at Petroleum Facilities Classified as Class I, Zone 0, Zone 1 and Zone 2
ASME B1.20.1, Pipe Threads, General Purpose (Inch)
ASME B31.3, Process Piping
ASME Boiler and Pressure Vessel Code (BPVC), Section IX: Welding and Brazing Qualifications
NACE MR 0175/ISO 15156 2 3, (all parts) Petroleum and natural gas industries—Materials for use in H2S containing
environments in oil and gas production
3
Terms, Definitions, and Abbreviations
3.1
Terms and Definitions
For the purposes of this standard, the following terms and definitions apply.
accumulator
Pressure vessel charged with inert gas and used to store hydraulic fluid under pressure.
acoustic control system
Subsea control system that uses coded acoustic signals for communications and is normally used as a secondary
control system having control of selected functions.
adapter spool
Spool used to connect drill-through equipment with different end connections, nominal size designations, and/or
pressure ratings to each other.
annular blowout preventer
annular BOP
Blowout preventer that uses a shaped elastomeric sealing element to seal the space between the tubular and the
wellbore or an open hole.
autoshear system
System designed to automatically shut in the wellbore in the event of a disconnect of the LMRP.
bell nipple
Piece of pipe, with an ID equal to or greater than the BOP bore, that is connected to the top of the BOP or marine
riser with a side outlet to direct the drilling fluid returns to the shale shaker pit.
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NOTE
This pipe usually has a second side outlet for the fill-up line connection.
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WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
3
bleed line
Flow line on the choke manifold that bypasses the chokes.
NOTE 1 This line allows circulation of the well with the preventers closed while maintaining a minimum backpressure.
NOTE 2 This line also permits the high-volume bleed-off of well fluids to relieve casing pressure with the preventers closed.
NOTE 3 Bleed lines can be referred to as panic lines.
blind ram
Closing and sealing component in a ram BOP that seals the open wellbore.
blind shear ram
BSR
Closing and sealing component in a ram BOP that first shears certain tubulars in the wellbore and then seals off
the bore or acts as a blind ram if there is no tubular in the wellbore.
blowout
Uncontrolled flow of well fluids and/or formation fluids from the wellbore to the surface or into lower-pressured
subsurface zones (underground blowout).
blowout preventer
BOP
Sealing ram or annular type device, which is within the scope of API 16A, installed on the wellhead or wellhead
assemblies to contain wellbore fluids either in the annular space between the casing and the tubulars or in an open
hole during well drilling, completion, and testing operations.
NOTE BOPs are not gate valves, workover/ intervention control packages, subsea shut‐in devices, API 16ST well control
components, intervention control packages, diverters, rotating heads, rotating control devices, rotating circulating devices,
capping stacks, snubbing or stripping packages, or non-sealing rams.
BOP control system (closing unit)
Equipment within the scope of API 16D used to operate the BOP stack.
BOP equipment
Equipment within the scope of API 16A.
BOP stack
Equipment within the scope of API 16A and API 16C that is connected to the top of the wellhead.
BOP system
BOP stack including the BOP controls system.
buffer chamber
Chamber installed downstream of the chokes to allow manifolding of the bleed lines together.
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4
API STANDARD 53
casing shear ram
CSR
Closing component in a ram BOP that is capable of shearing or cutting certain tubulars.
NOTE
CSRs are not required to seal.
choke
Device with either a fixed or variable aperture used to control the rate of flow of liquids and/or gas.
choke and kill equipment
Equipment within the scope of API 16C installed on the BOP stack, choke manifold, and between the BOP and
choke manifold.
choke line valve
kill line valve
Valve(s) connected to and a part of the BOP stack that control the flow to the choke and kill manifold.
choke line
kill line
High-pressure line(s) that allow fluid to be pumped into or removed from the well with the BOPs closed.
choke manifold
Assembly of valves, chokes, gauges, and lines used to control the rate of flow and pressure from the well when the
BOPs are closed.
clamp hub connection
Pressure-sealing device used to join two items without using conventional bolted flange joints.
NOTE
bolts.
The two items to be sealed are prepared with clamp hubs. These hubs are held together by a clamp containing four
closing ratio
Area of the operating piston exposed to the close operating pressure, divided by the cross-sectional area of the
piston shaft exposed to wellbore pressure.
competent person
Person with characteristics or abilities gained through training, experience, or both, as measured against the
manufacturer's or equipment owner’s established requirements.
control fluid
Hydraulic oil, water-based fluid, or gas that, under pressure, pilots the operation of control valves or directly operates
functions.
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WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
5
control pod
Assembly of valves and regulators (either hydraulically or electrically operated) that when activated will direct
hydraulic fluid through special apertures to operate the BOP equipment.
control station/panel
remote control station/panel
Panel containing an array of switches, push buttons, lights, valves, graphical user interfaces, pressure gauges,
and/or meters used to control or monitor functions, pressures, and alarms.
NOTE
A control station for a discrete hydraulic system can be at the HPU.
deadman system
System designed to automatically shut in the wellbore in the event of a simultaneous absence of hydraulic supply
and control of both subsea control pods.
dedicated accumulator system
Accumulators exclusively used for a specific purpose that are supplied by the main accumulator system or a
dedicated pump system, but not affected (e.g. by use of check valves) if the main supply is depleted or lost.
drill floor substructure
Foundation structure(s) on which the derrick, rotary table, drawworks, and/or other drilling equipment are supported.
drill pipe safety valve
Full-opening valve located on the rig floor with threads to match the drill pipe connections or other tubulars in use.
drilling spool
Pressure-containing component having end connections and outlets that is used below or between drill-through
equipment.
emergency disconnect sequence
EDS
Programmed sequence of events that operates the functions to leave the stack and controls in a desired state and
to disconnect the LMRP from the lower stack.
equipment manufacturer
original equipment manufacturer
OEM
current equipment manufacturer
CEM
Design owner of the traceable assembled equipment, single equipment unit, or component part.
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NOTE This valve is used to close off the drill pipe to prevent flow and may be crossed over to fit other connections and sizes
of tubulars being installed in the well.
6
API STANDARD 53
NOTE If any alterations to the original design and/or assembled equipment or component part are made by anyone other than
the OEM, then the assembly, part, or component is not considered an OEM product. The party that performs these alterations
is then designated as the CEM.
equipment owner
Purchaser or renter of the equipment to be installed on the wellhead.
NOTE
In most cases, this is the drilling contractor.
equipment user
Company that owns the well, wellhead, or wellhead assemblies on which the equipment is to be installed.
NOTE This entity may also be the equipment owner in cases where the equipment is rented from a third-party supplier, in part
or wholly, depending on the level of equipment supplied.
fill-up line
Line usually connected into the diverter housing, or bell nipple, above the BOPs to facilitate adding drilling fluid to
the hole at atmospheric pressure.
flex/ball joint
Device(s) installed between the bottom of the diverter and above the LMRP to permit relative angular movement of
the riser and to reduce stresses due to vessel motion and environmental forces.
flow line
Piping that exits the bell nipple and conducts drilling fluid and cuttings to the shale shaker and drilling fluid pits.
full-bore valve
Valve with unobstructed flow area dimensionally equal to or greater than the nominal size designation.
function test
Operation of a piece of equipment or a system to verify its intended operation.
gate valve
Valve that employs a sliding gate to open or close the flow passage.
NOTE
The valve may or may not be full opening.
hang-off
Action whereby the weight of that portion of the drill string below a ram BOP is supported by a tool joint resting on
the closed pipe ram or through the use of a special hang-off tool that lands in the wellhead.
high pressure, high temperature
Well conditions with a potential pressure greater than 15,000 psi (103.42 MPa) at the wellhead or with a potential
flowing temperature of greater than 350 °F (177 °C) at the wellhead.
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WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
7
hydraulic chamber test
Application of a pressure test to any hydraulic operating chamber to verify integrity.
hydrogen sulfide
H2S
Highly toxic, flammable, corrosive gas sometimes encountered in hydrocarbon-bearing formations.
hydrostatic head
Pressure that is exerted at any point in the wellbore due to the weight of the column of fluid above that point.
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initial test pressure
ITP
API pressure designation that is equal to or above well program MASP for a land or surface offshore BOP system.
NOTE
See Table 1 for API pressure designations.
inside blowout preventer
IBOP
Device that can be installed in the drill string that acts as a check valve, allowing drilling fluid to be circulated down
the string but preventing back flow.
inspection test
Examination or procedure that determine the existence of flaws that can influence equipment performance.
kelly valve
Valve installed immediately above and below the kelly that can be closed to confine pressures inside the drill string.
kick
Unintended influx of formation liquids or gas into the wellbore.
NOTE
Without corrective measures, this condition can result in a blowout.
maintenance
Disassembly, inspection, reassembly, replacement of components, and/or testing of equipment performed in
accordance with the equipment owner's maintenance program and the manufacturer’s guidelines.
NOTE This may include, but is not limited to: inspections, cleaning, polishing, function testing, pressure testing, NDE, and
change out of those parts defined in the maintenance system to be changed either periodically or on the basis of their condition.
maintenance panel
Control panel installed to provide control of the BOP for maintenance and testing purposes.
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8
API STANDARD 53
maintenance system
System that is used to schedule and document preventive/planned maintenance activities and document corrective
maintenance associated with rig equipment.
maximum anticipated surface pressure
MASP
Highest surface pressure predicted to be encountered while the well control equipment is installed.
NOTE
MASP may be calculated for each hole section during well construction.
maximum anticipated wellhead pressure
MAWHP
Highest subsea wellhead pressure predicted to be encountered while the well control equipment is installed.
NOTE
MAWHP may be calculated for each hole section during well construction.
maximum expected wellbore shear pressure
MEWSP
Expected operating pressure for a given hole section, a specific shear pressure requirement, specific operating
piston design, and material specification to shear drill pipe or tubing at the MASP (surface), MAWHP (subsea), or
other pressure-limiting value.
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minimum operating pressure
MOP
Minimum pressure differential required for a device to successfully perform its intended function in a particular
environment (i.e. well specific).
minimum operator pressure for low-pressure seal
MOPFLPS
BOP operator pressure required to affect a low-pressure wellbore seal when closing against zero initial wellbore
pressure.
mixing system
System that mixes a measured amount of water-soluble lubricant and, optionally, antifreeze or conditioning agents
into feed water and delivers it to a storage tank or reservoir.
mud/gas separator
Vessel used to remove entrained gas in drilling fluid.
multiplex control system
MUX
System utilizing electrical or optical conductors such that on each conductor, multiple distinct functions are
independently operated by dedicated serialized coded commands.
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WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
9
pipe ram
Closing and sealing component in a ram BOP that seals around the OD of a tubular in the wellbore.
pit volume totalizer
Device that combines all of the individual pit volume indicators and registers the total drilling fluid volume in the
various tanks.
pre-deployment test pressure
PDTP
One API pressure designation above well program MAWHP for a subsea BOP system, not to exceed the rated
working pressure (RWP) of the equipment being tested.
NOTE
See Table 2 for API pressure designations.
pressure-containing
Part whose failure to function as intended results in a release of wellbore fluid to the environment.
pressure-controlling
Part intended to control or regulate the movement of wellbore fluids.
pressure test
Periodic application of pressure to a piece of equipment or a system to verify the pressure containment capability
for the equipment or system.
rated working pressure
RWP
Maximum internal pressure that equipment is designed to contain or control.
repair
Replacement of parts or correction of damaged or worn components that does not include machining, welding, heat
treating, or other manufacturing operation.
remanufacture
Activity involving disassembly, reassembly, and testing of equipment where machining, welding, heat treating, or
other manufacturing operations are employed.
shearing ratio
SR
Area of the operating piston exposed to the close operating pressure during shearing operations divided by the
cross-sectional area of the piston shaft exposed to wellbore pressure (generally the higher value of the closing
ratios provided by the manufacturer).
NOTE
The SR is dependent on piston size and/or booster addition.
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pit volume indicator
Device installed in the drilling fluid tank to register the fluid level in the tank.
10
API STANDARD 53
spacer spool
Spool used to provide separation between two components with equal-sized end connections.
stable
State in which the pressure change rate has decreased to within documented acceptance criteria.
NOTE The documented acceptance criteria can include adjustments for different fluid types, air entrapment, compressibility,
and temperature effects.
surface base pressure
Minimum operating pressure of the hydraulic circuit for supplying power to the function(s).
NOTE 1 This is usually a regulated 1500 psig.
NOTE 2 Exceptions are to special functions that have a specific pressure requirement, such as shear rams used to cut a specific
drill pipe or tubing.
NOTE 3 This value is used in accumulator calculations as defined in API 16D and referenced in Annex A.
umbilical
Control hose bundle or electrical cable that runs from the reel on the surface to the subsea control pod on the
LMRP.
well control equipment
Equipment within the scope of API 16A, API 16C, API 16D, and the supporting auxiliary equipment referenced in
the scope of this document.
wetted elastomeric seal
Seal that comes in contact with wellbore fluids (e.g. annular packers, ram block seals, operator rod or stem seals,
valve seats, etc.).
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trip tank
Low-volume (100 barrels [15.9 m3] or less) calibrated tank that can be isolated from the remainder of the surface
drilling fluid system and used to accurately monitor the amount of fluid going into or coming from the well.
WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
3.2
Abbreviations
For the purposes of this standard, the following abbreviations apply.
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ANSI
American National Standards Institute
BOP
blowout preventer
BSR
blind shear ram
CEM
current equipment manufacturer
CSR
casing shear ram
EDS
emergency disconnect sequence
HPU
hydraulic power unit
H2S
hydrogen sulfide
IBOP
inside blowout preventer
ID
inside diameter
IOM
installation, operation, and maintenance
ITP
initial test pressure
LMRP
lower marine riser package
MBR
minimum bend radius
MGS
mud/gas separator
MPa
megapascal
MASP
maximum anticipated surface pressure
MAWHP
maximum anticipated wellhead pressure (for subsea wells)
MEWSP
maximum expected wellbore shear pressure
MOC
management of change
MOP
minimum operating pressure
MOPFLPS
minimum operator pressure for low-pressure seal
MUX
multiplex system
MWP
maximum working pressure
NACE
National Association of Corrosion Engineers
NDE
nondestructive examination (ultrasonic, radiographic, dye penetrant, acoustic emission,
etc.)
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11
12
API STANDARD 53
NIST
National Institute of Standards and Technology (U.S.)
OEC
other end connections
OEM
original equipment manufacturer
OD
outside diameter
P&ID
piping and instrumentation diagram
PDTP
pre-deployment test pressure
PM
preventive maintenance
PQR
procedure qualification record
RCFA
root cause failure analysis
RWP
rated working pressure
SME
subject matter expert
SOP
standard operating procedure(s)
SR
shearing ratio
SWL
safe working load
VBR
variable-bore ram
WPS
weld procedure specification
4
Well Control Equipment General Requirements
4.1
BOP Equipment
Specifications for BOP Equipment
4.1.1.1 BOP equipment shall be in accordance with the edition of API 16A or API 6A that was in effect at the time
of the equipment manufacture.
4.1.1.2
API 16AR should be used for BOP equipment remanufacturing.
4.1.1.3 Modifications, alterations, or adjustments from the original design or intent of the BOP system shall be
documented through the use of the equipment owner’s MOC (management of change) system.
4.1.2.1 The quantity of pressure containment sealing components in the vertical wellbore of a BOP stack (total
number of ram and annular preventers) shall be used to identify the classification or “class” for the BOP system
installed. For example, a Class 6 stack designation indicates a stack with a combination of six ram and/or annular
preventers installed (e.g. two annular and four ram preventers or one annular and five ram preventers).
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BOP Stack Classifications
WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
13
4.1.2.2 After the classification of the BOP stack has been identified, the next nomenclature identifies the quantity
of annular-type preventers installed and designated by an alphanumeric designation (e.g. A2 identifies that two
annular preventers are installed).
4.1.2.3 The final alphanumeric designation shall be assigned to the quantity of rams or ram cavities, regardless
of their use, installed in the BOP stack. The rams or ram cavities shall be designated with an “R” followed by the
numeric quantity of rams or ram cavities. (e.g. R4 designates that four ram-type preventers are installed).
NOTE For example, a Class 6 BOP stack installed with two annular-type and four ram-type preventers is designated as
“Class 6‑A2‑R4”.
4.1.3.1 Spacer spools may be used to allow additional space between preventers to facilitate stripping, hang off,
and/or shear operations, but can serve other purposes in a stack as well.
4.1.3.2 Adapter/spacer spools shall:
a) Have a minimum vertical bore diameter equal to the internal diameter of the mating equipment;
b) Have an RWP (rated working pressure) equal to or greater than the lowest RWP of the mating equipment;
c) Have no penetrations capable of exposing the wellbore to the environment.
Drilling Spools
4.1.4.1 Choke and kill lines may be connected either to side outlets of the BOPs or to a drilling spool installed
below at least one BOP capable of closing on pipe.
NOTE
Utilization of the ram-type BOP side outlets reduces the number of stack connections and overall BOP stack height.
However, a drilling spool may be used to provide stack outlets (to localize possible erosion in the dispensable spool) and to
allow additional space between preventers to facilitate stripping, hang off, and/or shear operations.
4.1.4.2 Drilling spools for BOP stacks shall meet the following minimum requirements:
a) For pressure-rated arrangements of 3K and 5K, have two side outlets no smaller than a 2 in. (5.08 cm) nominal
size.
b) For pressure-rated arrangements of 10K and greater, have two side outlets—one 3 in. (7.62 cm) nominal size as
a minimum and one 2 in. (5.08 cm) nominal size as a minimum.
c) Have a vertical bore diameter equal to the internal diameter of the mating BOPs and at least equal to the maximum
bore of the uppermost wellhead or wellhead assembly.
d) Have an RWP equal to the RWP of the installed ram BOP above the spool.
4.1.4.3
lines.
4.2
For drilling operations, wellhead or wellhead assembly outlets shall not be employed for choke or kill
Choke and Kill Equipment
Specifications for Choke and Kill Equipment
4.2.1.1 Choke and kill equipment shall be in accordance with the edition of API 16C that was in effect at the time
of manufacture.
The latest edition should be used for modifications, remanufactured equipment, or replacement equipment.
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Adapter/Spacer Spools
14
API STANDARD 53
4.2.1.2 Modifications, alterations, or adjustments from the original design or intent of the choke and kill system
shall be documented through the use of the equipment owner’s MOC system.
4.2.2.1 Choke and kill interconnect piping and piping downstream of the choke manifold shall be supported in
accordance with ASME B31.3.
4.2.2.2 Materials used in construction and installation shall be suitable for the expected service, in accordance
with API 16C.
4.2.2.3 Choke and kill equipment shall meet the area classification requirements for the area in which it is
installed.
NOTE
See API 500 and API 505 for information on area classification.
4.2.2.4 For systems operating in temperatures where freezing can occur, the manifold and piping shall be
protected from freezing.
4.2.2.5 If a component is used to connect the BOP or drilling spool outlet to the valves, the equipment owner's
maintenance system shall include an inspection of the component for erosion at least every two years.
4.2.2.6
Use of the outlet below the lower-most ram BOP to take returns should be avoided.
Choke Manifold Equipment
4.2.3.1 For wells with a MASP (maximum anticipated surface pressure) of 3000 psi and greater, flanged, welded,
and hubbed connections (as well as OECs [other end connections]) that are in accordance with API 6A and API
16A shall be employed on components subjected to well pressure.
4.2.3.2 Minimum ID (inside diameter) for lines downstream of the chokes shall be equal to or greater than the
nominal connection size of the choke inlet and outlet.
4.2.3.3
Choke manifold valves shall be full bore.
4.2.3.4 When buffer chambers are employed, provision shall be available to re-direct the flow path and to isolate
a failure or malfunction of the buffer chamber.
4.2.3.5
A choke manifold assembly shall include two adjustable chokes.
4.2.3.6
For land wells with a MASP of 3000 to 10,000 psi, at a minimum, one choke shall be remotely operable.
4.2.3.7 For land wells with a MASP greater than 10,000 psi, at a minimum, two chokes shall be remotely
operable.
4.2.3.8
For offshore wells with a MASP of 3000 to 5000 psi, at a minimum, one choke shall be remotely operable.
4.2.3.9 For offshore wells with a MASP greater than 5000 psi, at a minimum, two chokes shall be remotely
operable.
4.2.3.10 Choke manifold configurations shall allow for rerouting of flow (in the event of eroded, plugged, or
malfunctioning parts) through a different choke, without interrupting flow control.
4.2.3.11 Pressure ratings of all lines and sealing elements upstream of the chokes shall equal or exceed the MASP
for the well program.
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Choke and Kill General
WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
15
NOTE Pressure ratings for lines downstream of the adjustable choke outlet are not required to meet or exceed the MASP for
the well program.
4.2.3.12 The ID of the bleed line (if installed) shall be at least equal to the ID of the choke line.
4.2.3.13 Pressure gauges shall be installed to observe drill pipe and annulus pressures at the station where well
control operations are conducted.
4.2.3.14 The remote choke control station shall include the ability to control the remotely adjustable choke(s) and
to monitor casing pressure, standpipe pressure, and pump strokes.
4.2.3.15 The choke control panel shall be capable of independently adjusting each remotely operated choke.
4.2.3.16 Power systems for remotely operated valves and chokes shall be sized to provide the pressure and
volume required to operate the valve(s) at the RWP and flow conditions.
4.2.3.17 Any remotely operated valve or choke shall be equipped with an emergency backup power source or
manual override.
Choke and Kill Lines
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4.2.4.1
Choke and kill lines should be as straight as possible.
4.2.4.2 Block ells and tees should be targeted or have fluid cushions installed in the direction of flow (or in both
directions if bidirectional flow is expected).
4.2.4.3 If pipe bends with R/d < 10 are used without targets or fluid cushions installed in the direction of expected
flow (or in both directions if bidirectional flow is expected), the equipment owner’s maintenance system shall include
an inspection for erosion at the pipe bends at least every two years, where:
R is the radius of pipe bend measured at the centerline in inches (centimeters);
d is the ID of the pipe in inches (centimeters).
For large-radius pipe bends (R/d ≥ 10), targets or fluid cushions may not be necessary.
NOTE
4.2.4.4
4.3
The flexible line manufacturer's MBR (minimum bend radius) guidelines should be followed.
BOP Control Systems (Land, Surface Offshore, Subsea)
Specifications for BOP Controls Equipment
4.3.1.1 BOP control systems shall be in accordance with the edition of API 16D that was in effect at the time of
the control system manufacture. Systems designed before the first issue of API 16D shall meet the requirements
of API 16D first edition as a minimum.
The latest edition should be used for modifications, remanufactured equipment, or replacement equipment.
4.3.1.2 Modifications, alterations, or adjustments from the original design or intent of the BOP control system
shall be documented through the use of the equipment owner’s MOC system.
BOP Controls General
4.3.2.1
BOP controls equipment shall meet the area classification requirements for the area in which it is installed.
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16
API STANDARD 53
Control Fluid
4.3.3.1 Control fluid (gases and liquids) shall be selected and maintained to meet minimum BOP equipment
manufacturers and fluid supplier’s properties, and the equipment owner’s requirements.
4.3.3.2
The control fluid shall be maintained to prevent freezing when required.
Control Fluid Reservoir
4.3.4.1 Control fluid reservoirs shall be cleaned, flushed of contaminants, and have vents inspected before fluid
is introduced per the equipment owner's maintenance system.
Control Fluid Mixing System (If Applicable)
4.3.5.1 A check valve or some other automated means of preventing control fluid from returning or back flowing
to the potable water supply shall be provided.
4.3.5.2 A manual override of the automatic mixing system shall be tested to ensure proper operation per the
equipment owner's maintenance system.
Pump Systems
4.3.6.1
A minimum of two pump systems shall be required; a pump system may consist of one or more pumps.
4.3.6.2
The two required pump systems shall have independent power sources.
NOTE
Additional pump systems do not require independent power sources.
4.3.6.3 These pump systems shall be connected such that the loss of any one power source does not impair the
operation of all the pump systems.
4.3.6.4
At least one pump system shall be available while the BOP is in operation.
Hydraulic Control Unit Location
4.3.7.1
The hydraulic control unit should be outside the drill floor substructure.
4.3.8.1
A nonoxidizing inert gas, such as nitrogen or helium, shall be used for pre-charging accumulators.
4.3.8.2
Neither atmospheric air nor oxygen shall be used.
4.3.8.3
The gas used shall be in accordance with the accumulator design.
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Accumulator Systems
4.3.8.4 Subsea accumulators shall be discharged subsea prior to recovering the BOP stack to the surface or
include a relief device to prevent over-pressurization of the circuit.
Main Accumulator System
4.3.9.1 The main accumulator system consists of the surface accumulator system and any stack-mounted
accumulators that are part of the main control system (not dedicated accumulators for emergency or secondary
systems).
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WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
17
Dedicated Accumulator Systems
4.3.10.1 The dedicated accumulators shall be maintained (e.g. check valves) if the main supply is depleted or lost.
Accumulator Pre-charge
4.3.11.1 The pre-charge pressure for each surface accumulator bottle shall be measured and adjusted in
accordance with equipment owner's maintenance system.
4.3.11.2 The pre-charge pressure on each stack-mounted accumulator bottle shall be measured prior to BOP
stack deployment and adjusted in accordance with the API 16D method specified in the manufacturer’s sizing
documentation.
4.3.11.3 The manufacturer-supplied control system surface base pressure, adjusted for water depth and operating
temperature, shall be used as required.
4.3.11.4 Documentation of the accumulator pre-charge measurement and adjustment shall be retained and
retrievable until the end of the well.
4.3.11.5 The calculated pre-charge pressures, along with documentation supporting nonoptimal pre-charge
pressures (if used), shall be filed with the well-specific data package.
4.3.11.6 The pre-charge pressure shall not exceed the RWP of the accumulator.
NOTE The pre-charge pressure for subsea accumulators can exceed the pump pressure for deepwater applications that will
affect surface testing.
Accumulators, Valves, and Pressure Gauge Requirements
4.3.12.1 No accumulator bottle shall be operated at a pressure greater than its RWP.
4.3.12.2 Bladder- and float-type accumulators shall be mounted in a vertical position.
4.3.12.3 Accumulator pre-charge pressure gauges shall meet the requirements of 4.7.1.
Control System Interconnect Valves, Fittings, Lines, and Components
NOTE 1 This section applies to rigid or flexible control lines between the control system and BOP stack(s) or between control
system assemblies (e.g. HPUs [hydraulic power units], accumulator skids, etc.).
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4.3.13.1 Control system interconnect valves, fittings, and other components such as pressure switches,
transducers, transmitters, etc., shall have an RWP at least equal to the RWP of their respective circuit.
4.3.13.2 Piping components and all threaded pipe connections installed on the BOP control system shall conform
to the design and tolerance specifications as specified in ASME B1.20.1.
4.3.13.3 Pipe, pipe fittings, and components shall conform to the requirements of ASME B31.3.
4.3.13.4 Welding shall be performed in accordance with ASME BPVC, Section IX.
4.3.13.5 For BOP systems that do not include a deadman system, control lines and end connections between the
control system and BOP stack(s) located in a Div 1 or Div 2 area as defined in API RP 500 or a Zone 1 or Zone 2
area as defined by API RP 505 shall meet the requirements of API 16D, including fire test requirements.
NOTE 2 For BOP systems that include a deadman system, rigid or flexible control lines and hot line supply hoses between the
control system and BOP are not required to meet the fire test requirements of API 16D.
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API STANDARD 53
NOTE 3 The use of fire-retardant hoses can delay or prevent the activation of a deadman system.
4.3.13.6 Control system interconnect piping, tubing, hoses, linkages, etc., shall be protected from damage during
drilling operations and day-to-day equipment movement.
4.3.13.7 Manually operated control valves shall be clearly marked to indicate which function(s) each operates and
the position of the valves (e.g. open, closed, etc.).
Control Stations
4.3.14.1 The control system shall have the capability to control all of the BOP stack functions, including pressure
regulation and monitoring of all system pressures from at least two separate locations.
4.3.14.2 One control station location shall provide easy accessibility for the drill crew.
4.3.14.3 The other control station shall be placed away from the rig floor to provide safe access for operating the
BOPs during an emergency well control event.
4.3.14.4 Control systems shall clearly identify each function and the function position (e.g. open, closed, etc.).
4.3.14.5 When installed, the following functions shall be protected to avoid unintentional operation:
a) Shear rams close;
b) Blind rams close;
c) Riser connector primary and secondary unlock (LMRP [lower marine riser package] connector unlock);
d) Wellhead connector primary and secondary unlock;
e) Choke and kill hydraulic connectors unlock or stabs retract;
f)
Pod stab retract or unlock functions;
g) Emergency disconnect sequence.
4.3.14.6 The control station shall be equipped and maintained with measurement devices to indicate the following
(where the equipment/system is installed):
a) Surface accumulator pressure;
b) Regulated manifold pressure;
c) Regulated annular pressure;
d) Air supply pressure;
e) Manifold and annular read-backs;
f)
Flow metering;
g) LMRP accumulator pressure;
h) Stack accumulator pressure;
i)
Pod supply pressure;
j)
Pilot supply pressure;
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k) Control pod regulator pilot pressures;
l)
Other control pod regulator readback pressures.
4.3.14.7 Additional remote panels that do not have full BOP stack functionality may be installed.
4.3.15.1 There shall be two or more means of surface-to-subsea power fluid supply.
4.3.15.2 The umbilicals, hotline(s), and MUX (multiplex system) cable(s) shall be secured to prevent abrasive and
flexing damage.
4.3.15.3 The outer sheath shall be visually inspected for damage upon retrieval.
4.3.15.4 Reterminations, repairs, or splices shall be tested to the RWP of the system.
4.3.15.5 The end terminations should be inspected at retrieval.
4.3.15.6 Corrosion-resistant alloy fittings shall be used for umbilical end terminations.
4.3.15.7 The MUX cable electrical conductors and electrical insulation shall not be used as load-bearing
components in the cable assembly.
4.3.15.8 All underwater electrical cable terminations shall be sealed to prevent water migration into the cable in
the event of connector failure or leakage and to prevent water migration from the cable into the subsea connector
termination in the event of water intrusion into the cable.
4.3.15.9 Reel brakes and mechanical locks shall be engaged when the umbilical or cable has been spooled out
to the desired length unless an operational constant tension system is in use.
4.3.15.10 Reel drive mechanisms shall be fitted with guards to prevent accidental injury to personnel from rotating
components.
4.3.15.11 Reel controls shall be clearly marked with which reel they control.
4.3.15.12 The hoses and reels should be visually inspected daily during operation for leakage or failed valves,
hoses, fittings, or gauges.
4.3.15.13 Sheaves should facilitate running and retrieving through the moonpool and support the moonpool loop
that may be deployed to compensate for vessel heave.
4.3.15.14 Sheaves shall maintain a radius larger than or equal to the MBR of the umbilical/hose/MUX cable.
4.3.15.15 Sheaves shall be mounted to permit three-axis freedom of movement and prohibit damage to the
umbilical in normal ranges of anticipated movement.
4.3.15.16 Sheave mounting support ratings shall equal or exceed the SWL (safe working load) of the sheave.
4.4
Auxiliary Equipment
Kelly Valves
4.4.1.1 A minimum of two kelly valves shall be required, with the bottom valve being capable of use for stripping
operations.
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Umbilicals and Reels
20
API STANDARD 53
Drill Pipe Safety Valve
4.4.2.1 A drill pipe safety valve shall be readily available (i.e. stored in open position with wrench accessible) on
the rig floor.
4.4.2.2
This valve(s) and crossover sub(s) shall be equipped to screw into any drill string member in use.
4.4.2.3
The OD (outside diameter) of the drill pipe safety valve shall be suitable for running into the hole.
Inside Blowout Preventer
4.4.3.1 An IBOP (inside blowout preventer), drill pipe float valve, or drop-in check valve shall be available for use
when stripping the drill string into or out of the hole.
4.4.3.2
in use.
The valve(s), crossover sub(s), or profile nipple(s) shall be equipped to screw into any drill string member
Trip Tank
4.4.4.1
A trip tank shall be installed and used on all wells.
4.4.4.2
The trip tank volume readout may be visual or remote, preferably both.
4.4.4.3 The size and configuration of the tank should be such that volume changes of approximately one-half
barrel can be easily detected by the readout arrangement.
Pit Volume Measuring and Recording Devices
4.4.5.1
Pit volume measuring systems, complete with audible and visual alarms, shall be installed.
4.4.5.2
Audible and visual alarms shall be active during well operations.
4.4.5.3
A pit volume totalizer system shall be installed and used on all rigs.
Flow Rate Sensor
4.4.6.1 A flow rate sensor, complete with audible and visual alarms, shall be mounted in the flow line to provide
for early detection of formation fluid entering the wellbore or a loss of returns.
4.4.6.2
Audible and visual alarms shall be active during well operations.
Mud/Gas Separator
4.4.7.1 The safe operating limits shall be determined based on the well-specific requirements and the MGS
(mud/gas separator) sizing.
NOTE
4.4.7.2
Reference SPE-20430-PA, Mud/Gas Separator Sizing and Evaluation.
MGSs shall not be used for well production or well testing operations.
4.4.7.3 Wellbore fluid sent to the MGS shall be flow controlled (i.e. no uncontrolled flow to the MGS, such as
from the diverter).
4.4.7.4
system.
Maintenance and inspection of the MGS shall be in accordance with the equipment owner’s maintenance
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4.4.7.5
MGS.
The equipment owner’s maintenance system shall include annual wall thickness measurements for the
4.4.7.6
The equipment owner’s maintenance system shall include clearing of debris.
4.4.7.7 The vent lines shall be inspected in accordance with the equipment owner’s maintenance system to
ensure they are adequately braced.
4.4.7.8 Water or drilling fluid shall be pumped into the MGS inlet to verify unobstructed flow and proper operation
in accordance with the equipment owner’s maintenance system.
Flare/Vent Lines
4.4.8.1
All flare/vent lines piping supports shall be in accordance with ASME B31.3.
4.4.8.2
Flare/vent lines should be as straight as possible to minimize back pressure.
4.4.8.3
Flare/vent lines shall have provisions for flaring/venting during varying wind directions.
4.4.8.4 For H2S operations, the end of the flare line(s) shall be equipped with a remotely operated igniter to ignite
the gas.
Top Drive Equipment
4.4.9.2
The upper valve shall be remotely operated and controlled at the driller’s console.
4.4.9.3
The lower valve shall have the capability of being manually operated.
4.4.9.4 To prevent or stop flow up the drill pipe during tripping operations, a separate drill pipe valve should be
used rather than either of the top drive valves.
NOTE Flow up the drill pipe might prevent stabbing the valve. In that case, the top drive, with its valves, can be used, keeping
in mind the following precautions:
a)
Once the top drive’s manual valve is installed, closed, and the top drive disconnected, a crossover may be necessary in
order to install an inside BOP on top of the manual valve;
b)
Most top drive manual valves cannot be stripped into 7 5/8 in. (19.37 cm) or smaller casing.
4.5
System Pressure Sealing Components
General
NOTE
This section addresses the pressure-containing elements of the BOP system and choke and kill equipment.
Bolting
4.5.2.1 BOP and choke and kill equipment bolting and nuts shall be part of the PM (preventive maintenance)
program for the system.
4.5.2.2 The equipment owner’s PM program shall specify inspection frequency; NDE (nondestructive
examination); and acceptance criteria for bolts, studs, nuts, and clamps (if installed).
4.5.2.3
Replacement subsea BOP equipment bolting shall be in accordance with the latest edition of API 16A.
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4.4.9.1 There shall be two isolation valves that are located on top drive equipment and that have a minimum
RWP equal to the MASP or the circulating system RWP, whichever is greater.
22
API STANDARD 53
4.5.2.4 Replacement subsea choke and kill equipment bolting shall be in accordance with the latest edition of
API 16C.
Bolted Connections
4.5.3.1 Wellbore pressure-containing connections shall be preloaded in accordance with equipment
manufacturer’s recommendations.
NOTE 1 Torque is only one of several ways to preload a fastener.
4.5.3.2
Manuals or bulletins containing preload specifications shall be available on the rig.
4.5.3.3
The appropriate torque shall be applied for the lubricant in use.
4.5.3.4 After the first pressure test is completed on connections that were disconnected, the bolting shall be
checked for proper preload.
4.5.3.5
Bolting should not be used to force the end connections into alignment.
NOTE 2 Reference ASME B16.5 for flanged joint alignment.
4.5.3.6 When making up proprietary OEC clamp hub connections, the manufacturer's recommended procedure
shall be followed.
4.5.3.7 For subsea BOPs operating in hydrate-prone areas, the wellhead connector shall incorporate a means
to remotely inject hydrate inhibitors external to the primary sealing system and clamping arrangement.
NOTE 3 This port may also be used as an external low-pressure test to confirm the effectiveness of the hydrate seal, if one is
installed.
Ring-joint Gaskets
NOTE 1 Resilient ring gaskets may be used as a temporary means of obtaining a seal if approved by an MOC and risk
assessment for the applicable operations.
4.5.4.1
Metal ring gaskets shall not be re-used unless specifically designed for that purpose.
NOTE 2 Ring gaskets may be re-used for pre-deployment testing.
External to Internal Differential Pressure Effects on Ring-joint Gaskets
4.5.5.1 For subsea BOP stack applications, external to internal differential pressure capacity may be a
performance concern in the design of sealing for pressure-containing joints.
4.5.5.2 Equipment manufacturers shall provide equipment owners with external pressure capacity of ring-joint
gaskets utilized in subsea BOP stacks. This includes API RX, BX, SRX, and SBX gaskets used in API flanges and
hubs, as well as proprietary gaskets (AX, CX, VX, etc.) used in OECs.
4.5.5.3 For subsea BOP stacks, equipment manufacturers should clearly state the external pressure capacity of
each joint/seal, including valve stems, annular BOP seals, or ram-type piston-locking mechanisms at any point that
forms a barrier from internal to external pressure.
4.5.5.4 Subsea BOP system owners shall survey and evaluate all pressure-containing joints in the BOP stack(s)
to ensure adequate performance under the effects of external pressure capacity for the specific subsea applications.
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Wetted Elastomeric Sealing Components
4.5.6.1 Riser joints shall be visually inspected for damage or degradation to exposed elastomeric seals and seal
areas on riser connectors and on choke and kill connections prior to or during running the marine riser.
4.5.6.2 The equipment user shall consult the OEM (original equipment manufacturer) when compatibility testing
of drilling and completion fluids is required.
NOTE The fluid environment of wellbore wetted surfaces will vary depending on well circumstances. It is important to note
that some blends of drilling and completion fluids have detrimental effects on elastomeric seals.
4.5.6.3
fluid.
Elastomeric components shall be inspected or replaced if they are exposed to an incompatible wellbore
4.5.6.4 If applicable, elastomeric seals shall be verified for use in HPHT (high-pressure, high-temperature)
conditions and with extreme low-temperature and low-pressure variations.
Non-wellbore Wetted Elastomeric Components
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4.5.7.1 Non-wellbore wetted elastomeric seals that are routinely disconnected and exposed (e.g. control system
connections) shall be visually inspected for damage or degradation each time they are exposed.
NOTE 1 The non-wellbore wetted elastomeric sealing elements in the BOP system are used in control system components,
hydraulic actuators, and hydrate seals, etc. These seals are neither wellbore pressure-containing nor pressure-controlling.
NOTE 2 In the subsea control system, the primary hydraulic system seal between the male and female sections of the control
pods is typically accomplished with resilient seals.
NOTE 3 In the hydraulic junction boxes, there are stab subs or multiple check valve-type quick disconnect couplings where
again the primary seals are O-rings.
NOTE 4 In addition to the control system, hydraulic actuators may utilize elastomeric seals. These actuators include BOP
actuating systems and gate valve actuators.
Equipment Storage
4.5.8.1 Well control equipment should be stored in a manner that prevents degradation of the equipment's
integrity.
4.5.8.2 Before returning to service, the components shall be inspected and tested in accordance with the
equipment owner's or manufacturer's requirements.
4.5.8.3 Any elastomer seals found to be outside the manufacturer's recommended shelf-life expiration date shall
be prohibited from installation in BOP systems.
4.6
BOP Preventers for H2S Service
Applicability
4.6.1.1 Where there is a reasonable expectation of encountering H2S (hydrogen sulfide) gas zones that could
potentially result in the partial pressure of the H2S exceeding 0.05 psia (0.00034 MPa) in the gas phase at the
maximum anticipated pressure, the BOP and wellbore-wetted metallic equipment, excluding shear ram blades, shall
be in accordance with NACE MR0175/ISO 15156.
NOTE Guidelines for conducting drilling operations in such an environment can be found in API RP 49, Recommended
Practice for Drilling and Well Servicing Operations Involving Hydrogen Sulfide.
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API STANDARD 53
Equipment Verifications
4.6.2.1 Prior to installing a BOP stack on the location where H2S is expected, the equipment user shall confirm
that the below items are in accordance with NACE MR0175/ISO 15156:
a) Ram packers;
b) Ram shaft seals;
c) Annular seals;
d) Annular packers;
e) Choke and kill valve elastomeric components;
f)
Safety valves;
g) Top drive valves;
h) Inside BOP.
4.6.2.2 H2S is heavier than air and requires special attention for well control equipment. The following
equipment's discharge outlets should be routed to ensure that H2S is vented to a safe area during well control
events:
a) MGS vent outlet;
b) MGS discharge piping outlet;
c) Vacuum gas separator vent outlet;
d) Mud return area vent fans.
4.6.2.3 If the BOP has been activated and shut in for an emergency event during a sour well drilling operation,
elastomeric elements shall be replaced or inspected and tested in accordance with the equipment owner's
maintenance system.
4.6.2.4 When H2S is present, the well fluid shall be circulated (or other mitigation) prior to pressure testing BSRs
(blind shear rams) to minimize the effect of H2S on the higher-hardness metallic components.
NOTE
Reference NACE MR0175/ISO 15156 for other operational mitigation procedures.
4.6.2.5 When the BOP stack has been subjected to fluids containing H2S, the equipment manufacturer’s
recommendations shall be followed regarding the level of servicing and testing required during the maintenance
period.
4.7
Pressure Measurement Devices
Test Pressure Measurement Devices
4.7.1.1 Test results shall be recorded using test pressure gauges and chart recorders or data acquisition systems
that are calibrated annually according to the equipment manufacturer’s procedures and requirements.
4.7.1.2 Analog test pressure measurements shall be made at not less than 25 % and not more than 75 % of the
full pressure span.
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4.7.1.3 Electronic pressure gauges, chart recorders, and data acquisition systems shall be used within the
manufacturer’s specified range.
4.7.1.4
Calibrations shall be traceable to a recognized national calibration standard.
Operational Pressure Measurement Devices
4.7.2.1
range.
Analog and electronic pressure measurement devices shall be used within the manufacturer’s specified
4.7.2.2 It is acceptable for gauges to be used during normal operations to read full scale, but these shall not
serve as test gauges.
4.7.2.3
Operational pressure measurement devices shall be calibrated at least every three years.
4.7.2.4
Calibrations shall be traceable to a recognized national standard.
5
Surface BOP Systems (Land and Surface Offshore)
5.1
Surface BOP Stacks
Surface BOP Stack Pressure Designations
NOTE
BOP equipment is based on RWPs and designated as described in Table 1.
Table 1—Surface BOP Pressure Designations
RWP
2K
3K
5K
10K
15K
20K
25K
30K
2000 psi (13.79 MPa)
3000 psi (20.68 MPa)
5000 psi (34.47 MPa)
10,000 psi (68.95 MPa)
15,000 psi (103.42 MPa)
20,000 psi (137.90 MPa)
25,000 psi (172.37 MPa)
30,000 psi (206.84 MPa)
Every installed ram BOP shall have an RWP greater than or equal to the MASP to be encountered.
BOP Stack Capabilities
5.1.2.1 The system shall provide a means to:
a) Close and seal on the drill pipe, tubing, casing, or liner and allow circulation;
b) Close and seal on open hole and allow volumetric well control operations;
c) Strip the drill string;
d) Shear the drill pipe or tubing when BSRs are installed;
e) Circulate across the BOP stack to a choke manifold.
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5.1.1.1
Pressure
Designation
26
API STANDARD 53
Surface BOP Stack Arrangements
5.1.3.1
Annular preventers having a lower RWP than ram preventers shall be acceptable.
5.1.3.2 Rig-specific stack-identifying nomenclature (choke line, kill line, rams, annulars, etc.) shall be made part
of the drilling program.
5.1.3.3 A documented risk assessment shall be performed by the equipment user, with the participation of the
equipment owner, for all classes of BOP stack arrangements to identify ram configuration, outlet placements, and
choke and kill valve configurations. This assessment shall include tapered strings, casings, completion equipment,
test tools, etc. (See Figure 1 for example configuration.)
Figure 1—Example Land and Surface Offshore BOP
5.1.3.4 A minimum of a Class 2 BOP stack arrangement with one blind ram or BSR shall be installed for wells
with a MASP of 3000 psi or less.
NOTE 1 The second device may be a pipe ram or annular-type preventer, whichever is desired.
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5.1.3.5 A minimum of a Class 3 BOP stack arrangement with one blind ram or BSR and one pipe ram shall be
installed for wells with a MASP of greater than 3000 psi to 5000 psi.
NOTE 2 The third device may be a ram or annular-type preventer, whichever is desired.
5.1.3.6 A minimum of a Class 4 BOP stack arrangement with one annular, one blind ram or BSR, and one pipe
ram shall be installed for wells with a MASP of greater than 5000 psi to 10,000 psi.
NOTE 3 The fourth device may be a ram or annular-type preventer, whichever is desired.
5.1.3.7 A minimum of a Class 5 BOP stack arrangement with one annular, one BSR, and two pipe rams shall be
installed for wells with a MASP of greater than 10,000 psi.
NOTE 4 Additional device(s) may be a ram or annular-type preventer, whichever is desired.
5.1.3.8
All sealing ram-type preventers shall be equipped with locking devices.
Surface BOP Stack Risk Assessment for BSRs
5.1.4.1 Class 3 and Class 4 BOP stack arrangements shall conduct a risk assessment to determine if a BSR is
required.
NOTE
The risk assessment may cover multiple wells drilled in similar fields or geological formations.
5.1.4.2 The risk assessment shall be performed by the equipment user, with the participation of the equipment
owner, to determine whether a BSR is required on land BOP stacks.
5.1.4.3 The risk assessment in 5.1.4.1 shall include the following elements:
a) Proximity to an environmentally sensitive area;
b) H2S radius of exposure;
c) Proximity to populated areas;
d) Kick risks and planned mitigations;
e) Well control responses for all drill pipe, tubing in use, and other equipment run in the well;
f)
Analysis of the rig equipment and well control systems capabilities and limitations for the proposed
operations;
g) Exploration wells, limited subsurface data;
h) Flow potential;
i)
5.2
Simultaneous operations.
Choke Manifolds, Choke Lines, and Kill Lines—Surface BOP Installations
Choke and Kill Systems Pressure Designations
5.2.1.1 Surface BOP choke and kill systems shall provide access points to the BOP stack and allow for well
control operations as follows:
a) Circulating down the kill line and up the choke line;
b) Circulating down the drill pipe and up the choke line;
c) Pump/bullhead down the kill line;
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API STANDARD 53
d) Allow well pressure monitoring.
5.2.1.2
BOP or drilling spool outlet(s) connected to the choke or kill line shall have two fully opening valves.
5.2.1.3 On the choke line, one of these two valves shall be remotely controlled. (See Figure 2, Figure 3, and
Figure 4 for choke line examples.)
Figure 2—Example 2K and 3K RWP Choke Line and Choke Manifold for Land and Surface Offshore
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Figure 3—Example 5K and 10K RWP Choke Line and Choke Manifold for Land
Example 5K Choke Line and Choke Manifold for Surface Offshore
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Figure 4—Example 15K RWP or Greater Choke Line and Choke Manifold for Land
Example 10K RWP or Greater Choke Line and Choke Manifold for Surface Offshore
5.2.1.4
Wells with an MASP of 5000 psi or less shall have 2 in. (5.08 cm) ID or greater for choke lines.
5.2.1.5
Wells with an MASP of greater than 5000 psi shall have 3 in. (7.62 cm) ID or greater for choke lines.
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API STANDARD 53
5.2.1.6 Wells with an MASP greater than 3000 psi shall, at a minimum, consist of a kill line configuration with two
full-bore manual valves plus a check valve, or two full-bore valves, one of which is remotely operated. (See Figure
5, Figure 6, and Figure 7 for kill line examples.)
Figure 5—Example 2K RWP Kill Line for Land and Surface Offshore
Figure 6—Example 3K or Greater RWP Kill Line for Land and Surface Offshore
Figure 7—Example 3K or Greater RWP Kill Line for Land and Surface Offshore
5.2.1.7 Wells with an MASP of 3000 psi or less shall, at a minimum, consist of a kill line configuration with two
full-bore manual operated valves.
NOTE
Consider using a check valve in the kill line configuration for wells where H2S is expected.
5.2.1.8
The kill line shall be 2 in. (5.08 cm) ID or larger.
5.2.1.9 If a remote kill line is used, it should be connected to the kill line near the BOP stack and extended to an
auxiliary high-pressure pump at a safe location.
5.2.1.10 The kill line shall not be used as a fill-up line.
Testing—Surface BOP Systems
Purpose
5.3.1.1 The purpose for various field test programs on drilling well control equipment is to verify:
a) That specific functions are operationally ready;
b) Pressure integrity of the installed equipment;
c) Compatibility of the control system and BOP stack(s).
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5.3
WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
31
General
5.3.2.1 Site-specific procedures for testing of well control equipment shall be incorporated into acceptance tests;
installation; and subsequent tests, drills, periodic operating tests, maintenance practices, and drilling and/or
completion operations.
Inspection Tests
NOTE 1 Inspection test practices and procedure details may vary and are outside the scope of this document.
5.3.3.1 Inspection tests of well control equipment shall be performed in accordance with the equipment owner’s
maintenance system.
NOTE 2 Inspection tests may include, but are not limited to: visual, dimensional, audible, hardness, functional, pressure tests,
and electrical testing.
Competency
5.3.4.1
NOTE
Maintenance and testing shall be performed or supervised by a competent person(s).
Crew drills and well control rig practices are outside the scope of this document and are addressed in API RP 59.
Function Tests
5.3.5.1
Pressure tests shall qualify as function tests.
5.3.5.2 A function test shall be performed following the disconnection or repair and limited to the affected
component(s).
5.3.5.3 Remote panels where all BOP stack functions are not included (e.g. lifeboat panels, etc.) shall be function
tested in accordance with the equipment owner's procedures.
5.3.5.4
Initial function testing shall be performed before operations commence in accordance with Table C.1.
5.3.5.5
Subsequent operational function testing shall be performed in accordance with Table C.2.
5.3.5.6
Scheduled function testing shall be performed in accordance with Table C.3.
5.3.5.7
Actuation times (and volumes, if applicable) shall be recorded (see example worksheets in Annex B).
Control System Response Time
5.3.6.1 The measurement of the closing response time shall begin when the close function is activated at any
control panel and shall end when the BOP or valve is closed.
5.3.6.2 The following response times shall be met:
a) Close each ram BOP in 30 seconds or less;
b) Close annular BOPs of <18 3/4 in. nominal size in 30 seconds or less;
c) Close annular BOPs of ≥18 3/4 in. nominal size in 45 seconds or less;
d) Closing time shall be 30 seconds or less for non-sealing shear rams.
e) Response time for choke and kill valves (either open or close) shall not exceed the minimum observed ram close
response time.
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API STANDARD 53
Pressure Tests
5.3.7.1 All BOP components that can be exposed to well pressure shall be tested first to a low pressure between
250 psig to 350 psig (1.72 MPa to 2.41 MPa), and then to a high pressure.
5.3.7.2 Any initial pressure above 350 psig shall be bled back to a pressure between 250 psig and 350 psig
before starting the test. If the initial pressure exceeds 500 psig, pressure shall be bled back to zero and the test
shall be reinitiated.
NOTE The higher pressure can initiate a seal that can continue to seal after the pressure is lowered, therefore misrepresenting
a low-pressure condition.
5.3.7.3 The allowable test pressure tolerance above RWP shall not exceed 5 % of the RWP or 3.45 MPa
(500 psi), whichever is less.
5.3.7.4 A pressure test of the pressure containing component shall be performed following the disconnection or
repair, limited to the affected component.
5.3.7.5
Initial pressure testing shall be performed before operations commence in accordance with Table C.4.
5.3.7.6
Subsequent operational pressure testing shall be performed in accordance with Table C.5.
5.3.7.7 With larger-size annular BOPs, some small movement could continue within the large rubber mass for
prolonged periods after pressure is applied and may require a longer stabilization period.
5.3.7.8 Valves that are intended to seal against flow from both directions shall be pressure tested from both
directions.
5.3.7.9
Check valves installed on the kill line shall be low- and high-pressure tested from the wellbore side.
Hydraulic Chamber Tests
5.3.8.1 A hydraulic chamber test shall be included in the equipment owner’s maintenance system for operators
on hydraulic connectors, BOPs, and outlet valves attached to the BOPs.
5.3.8.2 Chamber pressure tests shall be performed and charted as follows:
a) When equipment operator is replaced, repaired, or remanufactured;
b) In accordance with Table C.6.
Test Fluids
5.3.9.1 The initial installation pressure tests shall be conducted with water or water with preservation, anti-freeze,
and colorant additives.
5.3.9.2
During operations, the drilling fluid in use is acceptable to perform subsequent tests of the BOP stack.
5.3.9.3 Control systems and hydraulic chambers shall be tested using clean control system fluids with lubricity
and corrosion additives for the intended service and operating temperatures.
Test Documentation
5.3.10.1 The results of BOP stack and choke manifold pressure and function tests shall be documented.
NOTE 1 Example worksheets are provided in Annex B.
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5.3.10.2 BOP stack and choke manifold pressure tests shall be documented with a pressure chart recorder or
equivalent data acquisition system.
5.3.10.3 Test documentation shall be signed by the pump operator, contractor’s representative, and operator’s
representative.
NOTE 2 This does not include maintenance testing such as hydraulic chamber tests.
5.3.10.4 Problems with the BOP system that result in an unsuccessful pressure test and actions to remedy the
problem(s) shall be documented per the equipment owner's procedures.
General Testing Requirements
5.3.11.1 Personnel should be alerted when pressure test operations are to be conducted, when testing operations
are underway, and when pressure testing has concluded.
5.3.11.2 Only designated personnel shall enter the test area to inspect for leaks when the equipment involved is
under pressure.
5.3.11.3 Tightening, repair, or any other work shall be done only after verification that the pressure has been
released.
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5.3.11.4 Pressure shall be released only through pressure release lines.
5.3.11.5 When pressure testing, a procedural method shall be used to confirm pressure has been bled off.
5.3.11.6 Lines and connections that are used in the test procedures shall be secured.
5.3.11.7 Fittings, connections, and piping used in pressure-testing operations shall have an RWP equal to or
greater than the maximum test pressure.
5.3.11.8 The drill pipe test joint should be capable of withstanding the tensile, collapse, and internal pressures that
will be placed on it during the test operation.
5.3.11.9 A procedure shall be developed to identify test plug leaks.
Surface BOP Stack Equipment
5.3.12.1 The entire stack shall be pressure tested as a unit.
5.3.12.2 Shearing of drill pipe is not required with function and pressure testing.
5.3.12.3 Prior to testing each ram BOP, the secondary rod seals (emergency pack-off assemblies) shall be
checked to ensure the packing has not been energized.
5.3.12.4 Should the ram shaft seal leak during the initial test, the seal shall be repaired rather than energizing the
secondary packing.
5.3.12.5 Manual ram locks shall be lubricated and inspected annually, at a minimum.
5.3.12.6 Manual lock operators (e.g. handwheels) shall be available at the rig site, ready and capable for operation.
Chokes and Choke Manifolds
5.3.13.1 The adjustable choke backup control system shall be tested to ensure operation in the event of a loss of
the primary power supply in accordance with the equipment owner's maintenance system.
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API STANDARD 53
Main Accumulator Drawdown Test
NOTE 1 It is important to distinguish between the standards for in-the-field control system accumulator capacity established in
this document and the sizing requirements established in API 16D.
NOTE 2 API 16D provides sizing requirements for designers and manufacturers of control systems. In the factory, it is not
possible to exactly simulate the volumetric demands of the control system piping, hoses, fittings, valves, BOPs, etc. On the rig,
efficiency losses in the operation of fluid functions result from causes such as friction, hose expansion, and control valve interflow,
as well as heat energy losses. Therefore, the establishment of the design accumulator capacity by the manufacturer provides a
safety factor. This safety factor is a margin of additional fluid capacity that is not intended to be used for operating well control
functions on the rig. For this reason, the control system design accumulator capacity formulas established in API 16D are
different from the demonstrable capacity requirements listed below.
5.3.14.1 A drawdown test shall be conducted by actuating the specified BOP operators or any combination of
available operators that draw the same or larger volume as the specified BOP operators.
5.3.14.2 Tests shall be completed at zero wellbore pressure.
5.3.14.3 Manifold and annular regulators shall be set at the manufacturer’s recommended operating pressure for
the BOP stack.
5.3.14.4 The test shall be performed as follows:
a) Position a properly sized joint of drill pipe or a test mandrel in the BOP, if required.
b) Turn off the power supply to all accumulator charging pumps (air, electric, etc.).
c) Record the initial accumulator pressure.
d) Close the largest-volume annular BOP or any combination of operators with an equivalent or larger volume.
Time each actuation. Response times shall be recorded.
e) Close a maximum of four BOP rams with the smallest cumulative operating volume or any combination of
operators with an equivalent or larger volume. Time each actuation. Response times shall be recorded.
f)
Open the hydraulic-operated valve(s) and record the time.
g) Record the final accumulator pressure; verify against acceptance criteria in Annex C table.
NOTE 3 The results of the test can be used to determine whether:
a)
Inadequate bottle pre-charge pressure exists;
b)
A failed bladder, piston, or float exists in the system;
c)
A temperature change has reduced effectiveness of the pre-charge gas;
d)
Other leakage from within the system has occurred;
e)
Improper alignment of valves has isolated some of the accumulator bottles.
NOTE 4 Reducing accumulator working pressure to accumulator pre-charge pressure during this test could expose the
accumulator bladders to damage. If the system is properly sized and operating as designed, this should not occur.
NOTE 5 A single BOP operator (pipe, blind, shear, or annular) may be functioned multiple times to simulate the multiple closure
of same-sized operators, or to draw the fluid equivalent of a larger operator such as a shear ram or annular. Inversely, a larger
operator can be used to simulate the draw of one or more smaller operators.
NOTE 6 When performing the accumulator drawdown test, it may be beneficial to wait one hour from the time the accumulator
system was initially charged from pre-charge pressure to operating pressure. Waiting the additional hour allows the accumulator
gas to cool to operating temperature.
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NOTE 7 Because it takes time for the gas in the accumulator to warm up after performing all of the drawdown test functions, it
is acceptable to wait 15 minutes after recording the pressure, if the pressure was less than the MOP (minimum operating
pressure). If there is an increase in pressure, indications are that the gases are warming and there is still sufficient volume in
the accumulators. If the MOP has not been reached after 15 minutes, an additional 15-minute wait may be required due to
ambient temperatures negatively affecting the gas properties. After 30 minutes from the time the final pressure was recorded, if
the MOP has not been reached, then it may be necessary to bleed down the system and verify pre-charge pressures and volume
requirements for the system.
5.4
Inspection and Maintenance—Surface BOP Systems
Inspections
5.4.1.1 Inspection and maintenance of the well control equipment shall be performed in accordance with the
equipment owner’s maintenance system.
5.4.1.2 The equipment owner’s maintenance system shall address the inspection (internal/external visual,
dimensional, NDE, etc.) of well control equipment system components.
Periodic Maintenance and Inspection
5.4.2.1 BOP stack and choke and kill equipment shall be inspected at least every five years in accordances with
the equipment owner’s maintenance system. Individual components and subassemblies may be inspected on a
staggered schedule. The inspection results shall be verified against one of the following:
a) the manufacturer’s acceptance criteria, or
b) the equipment owner’s acceptance criteria if the equipment owner collects and analyzes condition-based data
and performance data to justify their criteria.
5.4.2.2 The five-year period shall begin using one of the following criteria:
a) The date the equipment owner accepts delivery of a new build drilling rig with a BOP system;
b) The date that the inspected equipment is placed into service, when preservation and storage records in
accordance with 4.5.8 are available;
c) The date of the last inspection for the component, if preservation and storage records in accordance with 4.5.8
are not available.
NOTE As an alternative to the schedule-based inspection program referenced in 5.4.2.1, the inspection frequency may vary
from this five-year interval if the equipment owner collects and analyzes condition-based data (including performance data) to
establish a different frequency.
5.4.2.3 For schedule- and condition-based inspection programs, shear ram blades, shear ram blocks, and blade
retention bolts shall be inspected annually using visual inspection and surface NDEs. The inspection results shall
be verified against the manufacturer’s acceptance criteria.
5.4.2.4
Inspections shall be performed by a competent person(s).
5.4.2.5 Elastomeric components and the finishes of their seal surfaces should be inspected when equipment is
disassembled.
5.4.2.6
Documentation of all repairs and remanufacturing shall be maintained in accordance with 5.4.6.
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API STANDARD 53
Installation, Operation, and Maintenance Manuals
5.4.3.1 Procedures shall be maintained for the installation, operation, and maintenance of BOP equipment that
account for differing rig, well, and environmental conditions.
5.4.3.2 The IOM (installation, operation, and maintenance) manuals shall be available on the rig for the BOP
systems and choke and kill equipment installed on the rig.
Replacement Parts and Assemblies (non-OEM and OEM)
5.4.4.1 Replacement parts shall be in conformance with the relevant API standards and satisfy the
design/operating requirements.
5.4.4.2 The manufacturer's markings for BOP stack wellbore wetted elastomeric components, including the
durometer hardness, generic type of compound, date of manufacture, date of expiration, part number, and operating
temperature range of the component shall be verified and documented.
Welding
5.4.5.1 All welding of wellbore pressure-containing, pressure-controlling, and/or load-bearing components shall
be performed in accordance with the applicable API standards.
5.4.5.2 All welding of wellbore pressure-containing components shall comply with the welding requirements of
NACE MR0175/ISO 15156.
5.4.5.3 Verification of compliance shall be established through the implementation of a written WPS (weld
procedure specification) and the supporting PQR (procedure qualification record) from the repair facility.
5.4.5.4 Welding shall be performed in accordance with a WPS, written and qualified in accordance with ASME
BPVC, Section IX, Article II.
Planned Maintenance Program
5.4.6.1 A planned maintenance system, with equipment identified, tasks specified, and the time intervals between
tasks stated, shall be employed on each rig.
5.4.6.2 Electronic and/or hard copy records for maintenance, repairs, and remanufacturing performed for the well
control equipment shall be maintained on file at the rig site and preserved at an offsite location until the equipment
is permanently removed from service.
5.4.6.3 Electronic and/or hard copy records of remanufactured parts and/or assemblies shall be readily available
and preserved at an offsite location, including documentation that shows that the components meet applicable
specifications.
Manufacturer’s Product Alerts/Equipment Bulletins
5.4.7.1 Copies (electronic or paper) of equipment manufacturer's product alerts or equipment bulletins for the
well control equipment in use on the rig shall be maintained both at the rig site and at an offsite location.
Records and Documentation
5.4.8.1 Electronic and/or hard copies of applicable standards and specifications relative to the well control
equipment shall be available.
5.4.8.2
A P&ID (piping and instrumentation diagram) of the BOP control system shall be available at the rig.
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5.4.8.3 Equipment documentation and drawings shall be amended or updated and available at the rig site to
identify the current equipment and assist with procuring correct replacement parts.
Posted Documentation
5.4.9.1 Drawings showing ram space-out and bore of the BOP stack and a drawing of the choke manifold,
showing the pressure rating of the components shall be posted on the rig floor and maintained up to date.
5.4.9.2 Calculated shear pressures shall be posted on the rig floor and updated in accordance with drilling
operations (e.g. drill pipe properties, MASP, MEWSP [maximum expected wellbore shear pressure], leak-off tests,
mud weights, etc.).
5.4.9.3 For annular or ram preventers that require different closing pressures for different tubulars, closing
pressure shall be obtained, posted, and the regulator pressure adjusted prior to placing the tubular in the annular
or ram preventer.
Equipment Data Book and Certification
5.4.10.1 Equipment records (electronic or hard copy), manufacturing and/or remanufacturing documentation,
certifications, and factory acceptance testing reports shall be retained as long as the equipment remains in service.
5.4.10.2 Copies of the manufacturer’s equipment data book shall be available for review.
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5.4.10.3 Electronic and/or hard copies of documentation shall be retained at an offsite location as long as the
equipment remains in service.
Maintenance History and Failure Reporting—Offshore Surface
5.4.11.1 A maintenance and repair historical file shall be maintained by serial number or unique identification
number for each major piece of equipment.
5.4.11.2 Well control equipment malfunctions or failures, whether that component is in use or not and whether
there is non-productive time or not, shall be reported in writing to the equipment manufacturer in accordance with
Annex D.
5.4.11.3 Details of the BOP equipment, control system, and essential test data shall be maintained from the
beginning to the end of the well and considered for use in condition-based analysis.
5.4.11.4 Electronic and/or hard copies of all documentation shall be retained at an offsite location.
Maintenance History and Failure Reporting—Land
5.4.12.1 A maintenance and repair historical file shall be maintained by serial number or unique identification
number for each major piece of equipment.
5.4.12.2 The equipment owner shall report, in accordance with Annex D, well control equipment malfunctions or
failures that:
a) Result in harm to personnel;
b) Result in an unintended release of well bore fluids or control fluid to environment;
c) Cause equipment damage;
d) Are deemed by the equipment owner to be a failure that occurred prematurely in the maintenance lifecycle.
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API STANDARD 53
NOTE
Equipment repairs that are deemed by the equipment owner to be normal wear and tear are not required to be reported.
Test Procedures and Test Reports
5.4.13.1 Testing after major modifications or welding of well control equipment shall be performed according to
the manufacturer’s written procedures.
5.4.13.2 Rig-specific procedures for installation, removal, operation, and testing of all well control equipment
installed shall be available and followed.
5.4.13.3 Pressure and function test reports shall be recorded and retained including pre-installation and all
subsequent tests for each well.
5.4.13.4 Pressure and function test reports shall be readily available on the rig site for the duration of the well
program.
5.4.13.5 For surface offshore installations, pressure and function test reports shall be preserved at an offsite
location for a minimum of two years.
Shearing Pipe and Other Operational Considerations
5.4.14.1 Any identified well-specific risk(s) associated with the use of the BOP equipment and systems shall be
mitigated and/or managed through the development of specific guidelines, operational procedures, and a risk
assessment.
5.4.14.2 Due to the variations in pipe properties and corresponding shear pressures, the maximum expected
pressure for shearing pipe should be less than 90 % of the maximum operating pressure of the shear ram actuator.
NOTE 1 It is important to understand the effects of wellbore pressure and its impact on the capability of shearing the drill pipe
when the annular preventer is closed (see Table B.1).
5.4.14.3 An additional risk assessment should be performed if the shear pressure is higher than 90 % of the
maximum operating pressure of the shear ram actuator or the control system.
NOTE 2 Shearing capabilities may be determined by calculations or actual shear data for the pipe, BOP type, and configuration.
5.4.14.4 If the BSR or CSR (casing shear ram) are used to shear pipe, the ram block shall be inspected and the
BOP tested as soon as operations allow.
5.4.14.5 A plan shall be developed in preparation for well control operations that limits the drill string hang-off
weight to the manufacturer’s designed load capacity for each ram.
NOTE 3 Example hang-off procedures are included in API RP 59.
5.4.14.6 A pre-charged surge bottle may be installed adjacent to the annular preventer if contingency well control
procedures include stripping operations.
6
Subsea BOP Systems
6.1
Subsea BOP Stacks
Subsea BOP Stack Pressure Designations
6.1.1.1
BOP equipment is based on RWPs and designated as described in Table 2.
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Table 2—Subsea BOP Pressure Designations
Pressure
Designation
RWP
5K
5000 psi (34.47 MPa)
10K
10,000 psi (68.95 MPa)
15K
15,000 psi (103.42 MPa)
20K
20,000 psi (137.90 MPa)
25K
25,000 psi (172.37 MPa)
30K
30,000 psi (206.84 MPa)
6.1.1.2 Every installed ram BOP shall have, as a minimum, an RWP equal to the MAWHP (maximum anticipated
wellhead pressure) to be encountered.
BOP Stack Capabilities
6.1.2.1 The system shall provide a means to:
a) Close and seal on the drill pipe, tubing, casing, or liner and allow circulation;
b) Close and seal on open hole and allow volumetric well control operations;
c) Strip the drill string;
d) Hang-off the drill pipe on a ram BOP and control the wellbore;
e) Shear the drill pipe, tubing, or wireline in use;
f)
Disconnect the riser from the BOP stack;
g) Circulate across the BOP stack to a choke manifold.
Subsea BOP Stack Arrangements
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6.1.3.1
Annular preventers having a lower RWP than the ram preventers shall be acceptable.
6.1.3.2
The lowermost line connected to the BOP stack shall be designated as the kill line.
6.1.3.3 For BOPs that have lines installed on each side of the outlet below the lowermost well control ram, either
may be designated as a choke line or kill line.
NOTE
Either line can serve the choke or kill function.
6.1.3.4 A minimum of one choke line and one additional kill line connection shall be located above the lowest
well control ram BOP.
6.1.3.5
Annular bleed valves may be connected to either the choke or kill line.
6.1.3.6 Rig-specific stack identifying nomenclature (choke line, kill line, rams, annulars, etc.) shall be included in
the drilling program.
6.1.3.7 A documented risk assessment shall be performed by the equipment user and the equipment owner for
all classes of BOP stack arrangements to identify ram configuration, outlet placements, and choke and kill valve
configurations. This assessment shall include tapered strings, casings, completion equipment, test tools, etc. See
Figure 8 for a subsea BOP configuration example.
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API STANDARD 53
Figure 8—Example Subsea BOP
6.1.3.8 Subsea BOP stacks shall be Class 5 or greater and consisting of the following:
a) A minimum of one annular preventer;
b) A minimum two pipe rams (excluding the test rams);
c) A minimum of two sets of shear rams for shearing the drill pipe and tubing in use, of which at least one shall
be capable of sealing.
6.1.3.9 For moored rigs, a minimum of one set of BSRs (capable of sealing) for shearing the drill pipe and tubing
in use may be used after conducting a risk assessment in accordance with 6.1.4.
6.1.3.10 All sealing ram-type preventers shall be equipped with remotely operated locking devices.
Subsea BOP Stack Risk Assessment for Moored Vessels
6.1.4.1 The risk assessment process to justify the use of a Class 4 BOP stack or one BSR shall include the
elements described in 6.1.4.2 through 6.1.4.4.
6.1.4.2 The specific operations of the project shall be assessed; this assessment shall include the following at a
minimum:
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a) Drilling operations, completion operations, plug and abandon or workover operations, well testing, or flowback
to the facility;
b) Kick scenarios for all operations;
c) Well control responses for all drill pipe and tubing in use, and any other equipment run in the well;
d) Riser margin and the ability to balance the well with the hydrostatic pressure of seawater;
e) Unplanned disconnects;
f)
Riser failure.
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6.1.4.3 The capabilities of the rig and the existing well control equipment shall be assessed; this assessment
shall include the following at a minimum:
a) An analysis of the rig equipment and well control system capabilities and limitations for the proposed
operations;
b) The pressures required to close/seal the well with pipe rams and shear rams.
6.1.4.4 The station-keeping capabilities of the rig shall be assessed; this assessment shall include the following
at a minimum:
a) Metocean and environmental conditions,
b) Mooring components in use,
c) Mooring strength analysis,
d) Fatigue analysis,
e) Marine traffic/shipping lanes.
NOTE
6.2
See API 2MET and API 2SK for more information on metocean criteria and station-keeping systems respectively.
Choke Manifolds, Choke Lines, and Kill Lines—Subsea BOP Installations
Choke and Kill System Pressure Designations
6.2.1.1 Subsea BOP system choke and kill lines provide redundancy as well as multiple access points to the
BOP stack and allow for well control operations as follows:
a) Circulating down one line and up the other line,
b) Circulating down the drill pipe and up either or both lines,
c) Pump/bullhead down one or both lines,
d) Allow well pressure monitoring.
6.2.1.2
The choke and kill lines shall be identical in size and pressure rating.
6.2.1.3
The choke and kill lines shall be a minimum of 3 in. (7.62 cm) ID.
6.2.1.4
The manifold shall be 3 in. (7.62 cm) ID or larger. See Figure 9 for a subsea choke manifold example.
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6.3
API STANDARD 53
BOP Control Systems (Subsea)
Subsea Control Pods
6.3.1.1
Subsea stacks shall have redundant control pods.
6.3.1.2 Each control pod should contain all necessary valves and regulators to operate the BOP stack and LMRP
functions.
6.3.1.3 Auxiliary subsea electrical equipment that is not directly related to the BOP control system shall be
connected in a manner to avoid disabling the BOP control system in the event of a failure in the auxiliary equipment.
Emergency Disconnect Sequence—Primary Control System
6.3.2.1 An EDS (emergency disconnect sequence) shall be available on all subsea BOP stacks that are run from
a dynamically positioned vessel.
6.3.2.2
An EDS is optional for moored vessels.
Figure 9—Example Subsea Choke Manifold
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Autoshear System—Emergency Control System
6.3.3.1
Autoshear shall be installed on all subsea BOP stacks.
6.3.3.2
The autoshear system shall be armed while the BOP stack is latched onto a wellhead.
6.3.3.3 A documented MOC shall be required to disarm the system unless covered in the equipment owner’s
SOP (standard operating procedure).
NOTE The dedicated emergency accumulator system may be used for both the autoshear and deadman systems, as well as
for secondary control systems.
6.3.3.4 This dedicated emergency accumulator system shall be maintained (e.g. check valves) if the main supply
is depleted or lost.
6.3.4.1
A deadman system shall be installed on all subsea BOP stacks.
6.3.4.2
The deadman system shall be armed while the BOP stack is latched onto a wellhead.
6.3.4.3
SOP.
A documented MOC shall be required to disarm the system unless covered in the equipment owner’s
6.3.4.4 The dedicated emergency accumulator system may be used for both the autoshear and deadman
systems, as well as for secondary control systems.
6.3.4.5 This dedicated emergency accumulator system shall be maintained (e.g. check valves) if the main supply
is depleted or lost.
ROV Intervention—Secondary Control System
6.3.5.1 The BOP stack shall be equipped with ROV intervention equipment that, at a minimum, allows the
operation of critical functions (each sealing shear ram close and lock, each non-sealing shear ram close, one pipe
ram close and lock, and LMRP connector unlatch).
6.3.5.2 Hydraulic fluid can be supplied by an ROV, stack-mounted accumulators (which may be a shared
system), or an external hydraulic power source that shall be maintained at the well site.
6.3.5.3
The source of hydraulic fluid shall have necessary pressure to operate these functions.
6.3.5.4
All critical functions shall be fitted with a locking receptacle designed to accept an API 17H hot stab.
NOTE
See API 17TR15 for locking-type receptacles.
6.3.5.5 If multiple receptacle types are used, a means of positive identification of the receptacle type and function
shall be required.
Acoustic Control System—Secondary Control System
6.3.6.1
The acoustic control system is an optional secondary control system.
6.3.6.2
The acoustic control system should be capable of operating critical functions.
6.3.6.3 The dedicated accumulator system may be used for both the acoustic system and emergency control
systems.
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Deadman System—Emergency Control System
44
API STANDARD 53
6.3.6.4
or lost.
This dedicated accumulator system shall be maintained (e.g. check valves) if the main supply is depleted
MUX System Data Acquisition
6.3.7.1
MUX systems shall log data during the course of well drilling operations.
6.3.7.2 Data logged shall include, as a minimum, the time and date stamp, solenoid functions energized,
regulator and read-back pressures, flowmeter counts, and subsea accumulator pressures.
6.3.7.3
6.4
Data shall be retained in a manner that is easily retrievable (e.g. transmission to shore, backup).
Testing—Subsea BOP Systems
Purpose
6.4.1.1 The purpose for various field test programs on drilling well control equipment is to verify:
a) That specific functions are operationally ready,
b) The pressure integrity of the installed equipment,
c) The compatibility of the control system and BOP stack.
General
6.4.2.1 Site-specific procedures for testing of well control equipment shall be incorporated into acceptance tests,
pre-deployment, installation and subsequent tests, drills, periodic operating tests, maintenance practices, and
drilling and/or completion operations.
Inspection Tests
6.4.3.1
Inspection test practices and procedure details may vary and are outside the scope of this document.
NOTE Inspection tests may include, but are not limited to: visual, dimensional, audible, hardness, functional, pressure, and
electrical tests.
Competency
6.4.4.1
Maintenance and testing shall be performed or supervised by a competent person(s).
6.4.4.2 Crew drills and well control rig practices are outside the scope of this document and are addressed in
API RP 59.
Function Tests
6.4.5.1
Pressure tests qualify as function tests.
6.4.5.2 A function test of the BOP control system shall be performed following the disconnection or repair and
limited to the affected component.
6.4.5.3 Remote panels where all BOP stack functions are not included (e.g. lifeboat panels, etc.) shall be function
tested in accordance with the equipment owner's procedures.
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6.4.3.2 Inspections of all well control equipment shall be performed in accordance with the equipment owner’s
maintenance system.
WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
45
6.4.5.4 Pre-deployment function testing shall be performed before deployment of the BOP in accordance with
Table C.7.
6.4.5.5 Initial function testing shall be performed after the BOP has been latched to the wellhead and before
operations commence in accordance with Table C.8.
6.4.5.6
Subsequent operational function testing shall be performed in accordance with Table C.9.
6.4.5.7
Scheduled function testing shall be performed in accordance with Table C.10.
6.4.5.8 Actuation times (and volumes, if applicable) shall be recorded in a database for evaluating trends (see
example worksheets in Annex B).
Control System Response Time
6.4.6.1 Measurement of closing response time shall begin when the close function is activated at any control
panel and shall end when the BOP or valve is closed.
6.4.6.2 The following response times shall be met by at least one of the surface/subsea power supplies:
a) Close each ram BOP in 45 seconds or less;
b) Close each annular BOP in 60 seconds or less;
c) Unlatch the riser (LMRP) connector in 45 seconds or less;
d) Close non-sealing shear rams in 45 seconds or less;
e) Response time for choke and kill valves (either open or close) shall not exceed the minimum observed ram
close response time.
Pressure Tests
6.4.7.1 All blowout prevention components that can be exposed to well pressure shall be tested first to a low
pressure between 250 psig to 350 psig (1.72 MPa to 2.41 MPa), and then to a high pressure.
6.4.7.2 Any initial pressure higher than 350 psig shall be bled back to a pressure between 250 and 350 psig
before starting the test. If the initial pressure exceeds 500 psig, it shall be bled back to zero and the test reinitiated.
NOTE 1 The higher pressure can initiate a seal that can continue to seal after the pressure is lowered, therefore misrepresenting
a low-pressure condition.
6.4.7.3 The allowable test pressure tolerance above the RWP shall not exceed 5 % of RWP or 3.45 MPa (500
psi), whichever is less.
6.4.7.4 A pressure test of the pressure-containing component shall be performed following the disconnection or
repair, limited to the affected component.
6.4.7.5 Pre-deployment pressure testing shall be performed before deployment of the BOP in accordance with
Table C.11.
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6.4.7.6 Initial pressure testing shall be performed after the BOP has been latched to the wellhead and before
operations commence in accordance with Table C.12.
6.4.7.7
Subsequent operational pressure testing shall be performed in accordance with Table C.13.
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API STANDARD 53
NOTE 2 With larger-size annular BOPs, some small movement could continue within the large rubber mass for prolonged
periods after pressure is applied and may require a longer stabilization period.
6.4.7.8
Choke/kill isolation test valves are not well control valves and shall not require pressure testing.
6.4.7.9 Valves that are intended to seal against flow from both directions shall be pressure tested from both
directions.
Hydraulic Chamber Test
6.4.8.1 A hydraulic chamber test shall be included in the equipment owner’s maintenance system for operators
on hydraulic connectors, BOPs, and outlet valves attached to the BOPs.
6.4.8.2 Chamber pressure tests shall be performed and charted as follows:
a) When equipment is replaced, repaired or remanufactured;
b) In accordance with Table C.14.
Test Fluids
6.4.9.1 The pre-deployment and initial installation pressure tests shall be conducted with water or water with
preservation, anti-freeze, and colorant additives.
NOTE
During operations, the drilling fluid in use is acceptable to perform subsequent tests of the BOP stack.
6.4.9.2 Control systems and hydraulic chambers shall be tested using clean control system fluids with lubricity
and corrosion additives for the intended service and operating temperatures.
Test Documentation
6.4.10.1 The results of BOP stack and choke manifold pressure and function tests shall be documented.
NOTE 1 Example worksheets are provided in Annex B.
6.4.10.2 BOP stack and choke manifold pressure tests shall be documented with a pressure chart recorder or
equivalent data acquisition system.
6.4.10.3 Test documentation shall be signed by the pump operator, contractor’s representative, and operator’s
representative.
NOTE 2 This does not include maintenance testing such as hydraulic chamber tests.
6.4.10.4 Problems with the BOP system that results in an unsuccessful pressure test and actions to remedy the
problems shall be documented per the equipment owner's procedures.
General Testing Requirements
6.4.11.1 Personnel should be alerted when pressure test operations are to be conducted, when testing operations
are underway, and when pressure testing has concluded.
6.4.11.2 Only designated personnel shall enter the test area to inspect for leaks when the equipment involved is
under pressure.
6.4.11.3 Tightening, repair, or any other work shall be done only after verification that the pressure has been
released.
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6.4.11.4 Pressure shall be released only through pressure release lines.
6.4.11.5 When pressure testing, a procedural method shall be used to confirm that pressure has been bled off.
6.4.11.6 Lines and connections that are used in the test procedures shall be secured.
6.4.11.7 Fittings, connections, and piping used in pressure-testing operations shall have pressure ratings equal to
or greater than the maximum test pressure.
6.4.11.8 The drill pipe test joint should be capable of withstanding the tensile, collapse, and internal pressures that
will be placed on it during the test operation.
6.4.11.9 A procedure shall be developed to identify test plug leaks.
Subsea Well Hop
6.4.12.1 Upon latching to the subsequent well, all disconnected pressure-containing BOP system connections
shall be pressure tested in accordance with Table C.12.
6.4.12.2 If the MAWHP of the subsequent well exceeds the test pressure of the previous well, the well control
components shall be tested in accordance with Table C.12.
NOTE If the MAWHP of the subsequent well is less than or equal to the test pressure from the previous well, the well control
components may be tested in accordance with Table C.13 to provide a full 21 days before subsequent pressure testing is
required.
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6.4.12.3 The BOP rams, annulars, and choke and kill valves shall be function-tested in accordance with Table C.8.
6.4.12.4 Upon latching to the subsequent well, disconnected control system connections shall be function-tested
at the maximum pressures expected for well control operations.
6.4.12.5 When drilling wells in different water depths without retrieving the BOP stack, the control system precharge values shall be calculated and set such that they are suitable for use in all of the intended water depths in
accordance with 4.3.11.
6.4.12.6 Main accumulator systems that utilize the volume of the LMRP accumulators shall be drawdown-tested
in accordance with Table C.8 for water depth variations greater than 250 feet.
6.4.12.7 The dedicated shear accumulators shall be tested in accordance with Table C.8 for water depth variations
greater than 250 feet.
6.4.12.8 The previous dedicated shear accumulator test results shall be verified to meet or exceed the MOP when
there is an increase in:
a) MAWHP of 500 psia or more above previous well test pressure,
b) Drill pipe shearing requirements.
Subsea BOP Stack Equipment
6.4.13.1 Unless restricted by height, the entire stack (LMRP mated upon the lower BOP) should be pressuretested as a unit during pre-deployment.
6.4.13.2 Shearing of drill pipe is not required with function and pressure testing.
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API STANDARD 53
Chokes and Choke Manifolds
6.4.14.1 The adjustable choke backup control system shall be tested to ensure operation in the event of a loss of
the primary power supply in accordance with the equipment owner's maintenance system.
NOTE
Adjustable chokes are not required to be full sealing devices. Pressure-testing against a closed choke is not required.
Main Accumulator Drawdown Test
NOTE 1 It is important to distinguish between the standards for in-the-field control system accumulator capacity established in
this document and the sizing requirements established in API 16D.
NOTE 2 API 16D provides sizing requirements for designers and manufacturers of control systems. In the factory, it is not
possible to exactly simulate the volumetric demands of the control system piping, hoses, fittings, valves, BOPs, etc. On the rig,
efficiency losses in the operation of fluid functions result from causes such as friction, hose expansion, and control valve interflow,
as well as heat energy losses. Therefore, the establishment by the manufacturer of the design accumulator capacity provides a
safety factor. This safety factor is a margin of additional fluid capacity that is not intended to be used for operating well control
functions on the rig. For this reason, the control system design accumulator capacity formulas established in API 16D are
different from the demonstrable capacity requirements listed below.
6.4.15.1 A drawdown test shall be conducted by actuating the specified BOP operators or any combination of
available operators that draw the same or larger volume as the specified BOP operators.
6.4.15.2 Tests shall be completed at zero wellbore pressure.
6.4.15.3 Manifold and annular regulators shall be set at the manufacturer’s recommended operating pressure for
the BOP stack.
6.4.15.4 The test shall be performed as follows.
a) Position a properly sized joint of drill pipe or a test mandrel in the BOP, if required.
b) Turn off the power supply to all accumulator charging pumps (air, electric, etc.).
c) Record the initial accumulator pressure.
d) Close and open the largest-volume annular BOP or any combination of operators with an equivalent or larger
volume. Time each actuation. Response times shall be recorded.
e) Close and open the four least-cumulative operating volume BOP rams or any combination of operators with an
equivalent or larger volume. Time each actuation. Response times shall be recorded.
f)
Record the final accumulator pressure; verify against acceptance criteria in the applicable tables of Annex C.
a)
Inadequate bottle pre-charge pressure exists;
b)
A failed bladder, piston, or float exists in the system;
c)
A temperature change has reduced effectiveness of the pre-charge gas;
d)
Other leakage from within the system has occurred;
e)
Improper alignment of valves has isolated some of the accumulator bottles and verifies piping lineup.
NOTE 4 Reducing accumulator working pressure to accumulator pre-charge pressure during this test could expose the
accumulator bladders to damage. If the system is properly sized and operating as designed, this should not occur.
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NOTE 3 The results of the test can be used to determine whether:
WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
49
NOTE 5 A single BOP operator (pipe, blind, shear, or annular) may be used multiple times to simulate the multiple closure of
same-sized operators or to draw the fluid equivalent of a larger operator such as a shear ram or annular. Inversely, a larger
operator can be used to simulate the draw of one or more smaller operators.
NOTE 6 When performing the accumulator drawdown test, it may be beneficial to wait one hour from the time the accumulator
system was initially charged from pre-charge pressure to operating pressure. Waiting the additional hour allows the accumulator
gas to cool to operating temperature.
NOTE 7 Because it takes time for the gas in the accumulator to warm up after performing all of the drawdown test functions, it
is permissible to wait 15 minutes after recording the pressure if the pressure was less than the MOP. If there is an increase in
pressure, indications are that the gases are warming and there is still sufficient volume in the accumulators. If the MOP has not
been reached after 15 minutes, an additional 15-minute wait may be necessary due to ambient temperatures negatively affecting
the gas properties. After 30 minutes from the time the final pressure was recorded, if the MOP has not been reached, then it
may be necessary to bleed down the system and verify pre-charge pressures and volume requirements for the system.
6.5
Inspection and Maintenance—Subsea BOP Systems
Inspections
6.5.1.1 Inspection and maintenance of the well control equipment shall be performed in accordance with the
equipment owner’s maintenance system.
6.5.1.2 The equipment owner’s maintenance system shall address inspection (internal/external visual,
dimensional, NDE, etc.) of well control equipment system components.
Periodic Maintenance and Inspection
6.5.2.1 BOP stack, BOP stack-mounted control equipment, and choke and kill equipment shall be inspected at
least every five years in accordance with the equipment owner’s maintenance system. Individual components and
subassemblies may be inspected on a staggered schedule. The inspection results shall be verified against one of
the following:
a) the manufacturer’s acceptance criteria, or
b) the equipment owner’s acceptance criteria if the equipment owner collects and analyzes condition-based data
and performance data to justify their criteria.
6.5.2.2 The five-year period shall begin using one of the following criteria:
a) The date the equipment owner accepts delivery of a new build drilling rig with a BOP system;
b) The date inspected equipment is placed into service when preservation and storage records in accordance
with 4.5.8 are available;
c) The date of the last inspection for the component, if preservation and storage records in accordance with
4.5.8 are not available.
6.5.2.3 As an alternative to a schedule-based inspection program referenced in 6.5.2.1, the inspection frequency
may vary from this five-year interval if the equipment owner collects and analyzes condition-based data (including
performance data) to establish a different frequency.
6.5.2.4 For schedule- and condition-based inspection programs, shear ram blades, shear ram blocks, and blade
retention bolts shall be inspected annually by visual inspection and surface NDEs. The inspection results shall be
verified in accordance with 6.5.2.1.
6.5.2.5
Inspections shall be performed by a competent person(s).
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API STANDARD 53
6.5.2.6 Elastomeric components and the finishes of their seal surfaces should be inspected when the equipment
is disassembled.
6.5.2.7
Documentation of all repairs and remanufacturing shall be maintained in accordance with 6.5.6.
6.5.3.1 Procedures shall be maintained for the installation, operation, and maintenance of BOP equipment that
account for differing rig, well, and environmental conditions.
6.5.3.2 The IOM manuals shall be available on the rig for the BOP systems and choke and kill equipment installed
on the rig.
Replacement Parts and Assemblies (non-OEM and OEM)
6.5.4.1 Replacement parts shall be in conformance with the relevant API standards and satisfy the
design/operating requirements.
6.5.4.2 The manufacturer's markings for BOP stack wellbore wetted elastomeric components, including the
durometer hardness, generic type of compound, date of manufacture, date of expiration, part number, and operating
temperature range of the component, shall be verified and documented.
Welding
6.5.5.1 All welding of wellbore pressure-containing, pressure-controlling, and/or load-bearing components shall
be performed in accordance with the applicable API standards.
6.5.5.2 All welding of wellbore pressure-containing components shall comply with the welding requirements of
NACE MR0175/ISO 15156.
6.5.5.3 Verification of compliance shall be established through the implementation of a written WPS and the
supporting PQR from the repair facility.
6.5.5.4 Welding shall be performed in accordance with a WPS written and qualified in accordance with ASME
BPVC, Section IX, Article II.
Planned Maintenance Program
6.5.6.1 A planned maintenance system, with equipment identified, tasks specified, and the time intervals between
tasks stated, shall be employed on each rig.
6.5.6.2 Electronic and/or hard copy records for maintenance, repairs and remanufacturing performed for the well
control equipment shall be both maintained on file at the rig site and preserved at an offsite location until the
equipment is permanently removed from service.
6.5.6.3 Electronic and/or hard copy records of remanufactured parts and/or assemblies shall be readily available
and preserved at an offsite location, including documentation that shows that the components meet applicable
specifications.
Manufacturer’s Product Alerts/Equipment Bulletins
6.5.7.1 Copies (electronic or paper) of the equipment manufacturer's product alerts or equipment bulletins for the
well control equipment in use on the rig shall be maintained both at the rig site and at an offsite location.
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Installation, Operation, and Maintenance Manuals
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51
Records and Documentation
6.5.8.1 Electronic and/or hard copies of applicable standards and specifications relative to the well control
equipment shall be available.
6.5.8.2
A P&ID of the BOP control system shall be available at the rig.
6.5.8.3 Equipment documentation and drawings shall be amended or updated and available at the rig site to
identify the current equipment and assist with procuring the correct replacement parts.
Posted Documentation
6.5.9.1 Drawings showing ram space out and bore of the BOP stack and a drawing of the choke manifold showing
the pressure rating of the components shall be posted on the rig floor and maintained up to date.
6.5.9.2 Calculated shear pressures shall be posted on the rig floor and updated in accordance with drilling
operations (e.g. drill pipe properties, MAWHP, MEWSP, leak-off tests, mud weights, etc.).
6.5.9.3 For annular or ram preventers that require different closing pressures for different tubulars, the closing
pressure shall be obtained, posted, and the regulator pressure adjusted prior to placing the tubular in the annular
or ram preventer.
6.5.9.4
Documentation shall include the maximum riser angle and watch circle.
Equipment Data Book and Certification
6.5.10.1 Equipment records (electronic or hard copy), manufacturing and/or remanufacturing documentation,
certifications, and factory acceptance testing reports shall be retained as long as the equipment remains in service.
6.5.10.2 Copies of the manufacturer’s equipment data book shall be available for review.
6.5.10.3 Electronic and/or hard copies of documentation shall be retained at an offsite location as long as the
equipment remains in service.
Maintenance History and Failure Reporting
6.5.11.1 A maintenance and repair historical file shall be maintained by serial number or unique identification
number for each major piece of equipment.
6.5.11.2 Well control equipment malfunctions or failures, whether that component is in use or not and whether
there is non-productive time or not, shall be reported in writing to the equipment manufacturer in accordance with
Annex D.
6.5.11.3 Details of the BOP equipment, control system, and essential test data shall be maintained from the
beginning to the end of the well and considered for use in condition-based analysis.
6.5.11.4 Electronic and/or hard copies of all documentation shall be retained at an offsite location.
Test Procedures and Test Reports
6.5.12.1 Testing after major modifications or welding of well control equipment shall be performed according to
the manufacturer’s written procedures.
6.5.12.2 Rig-specific procedures for installation, removal, operation, and testing of all well control equipment
installed shall be available and followed.
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API STANDARD 53
6.5.12.3 Pressure and function test reports shall be recorded and retained, including pre-installation and all
subsequent tests for each well.
6.5.12.4 Pressure and function test reports shall be retained for a minimum of two years at the rig site, and copies
of these documents shall be retained at a designated offsite location.
Shearing Pipe and Other Operational Considerations
6.5.13.1 Any identified well-specific risk(s) associated with the use of the BOP equipment and systems shall be
mitigated and/or managed through the development of specific guidelines, operational procedures, and a risk
assessment.
6.5.13.2 Due to the variations in pipe properties and corresponding shear pressures, the maximum expected
pressure for shearing pipe should be less than 90 % of the maximum operating pressure of the shear ram actuator.
NOTE 1 It is important to understand the effects of wellbore pressure and its impact on the capability of shearing the drill pipe
when the annular preventer is closed (see Table B.2).
6.5.13.3 An additional risk assessment should be performed if the shear pressure is higher than 90 % of the
maximum operating pressure of the shear ram actuator or the control system.
NOTE 2 Shearing capabilities may be determined by calculations or actual shear data for the pipe, BOP type, and configuration.
6.5.13.4 If the BSR or CSR are used to shear pipe, the ram block shall be inspected and the BOP tested as soon
as operations allow.
6.5.13.5 If the BSR is incapable of both shearing and sealing the drill pipe or tubing in use, the emergency and
secondary systems shall be capable of closing two rams—one that will shear and one that will seal wellbore
pressure. Additional functions may be added, but shall not interfere with the main purpose of shearing drill pipe and
sealing the well.
6.5.13.6 In the event that non-shearable equipment is across the BOP and the emergency and secondary
system(s) have been disarmed, the priority of preserving life shall be given to disconnect the LMRP from the well.
6.5.13.7 While in use, a closed preventer should not be subjected to a differential pressure from above, beyond
the capabilities endorsed by the manufacturer.
NOTE 3 BOPs are designed to hold pressure from below.
a)
If such a condition develops, pressure should be equalized before opening the rams or packer.
b)
If the pressure differential was beyond the manufacturer rating, the preventer shall be pressure tested as soon as
operations allow.
6.5.13.8 A plan shall be developed in preparation for well control operations that limits the drillstring hang-off
weight to the manufacturer’s designed load capacity for each ram.
NOTE 4 Example hang-off procedures are included in API RP 59.
NOTE 5 A pre-charged surge bottle may be installed adjacent to the annular preventer if contingency well control procedures
include stripping operations.
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Annex A
(normative)
Accumulator Pre-charge
A.1 Accumulator Pre-charge Calculations
A.1.1 General
Accumulator sizing calculation Methods A, B, and C are defined in API 16D.
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The accumulator pre-charge shall be applied utilizing the calculation method used in the accumulator system design
sizing.
The optimal or user-determined pre-charge shall be confirmed to not exceed the accumulator system design sizing
using the appropriate well-specific input requirements.
All conditions that affect the MOP shall be included in the MOP calculation (excluding main accumulator drawdown
test calculation). Examples of conditions include shearing pressure, MOPFLPS (minimum operator pressure for
low-pressure seal), wellbore pressure effects, shearing/closing ratios, effective vent pressure, etc.
53
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Annex B
(informative)
Example Worksheets and Calculations
Figure B.1—Example BOP Function Test Worksheet for Land and Surface Offshore
54
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The worksheets in Figure B.1, Figure B.2, Figure B.3, and Figure B.4 and MEWSP calculations in Table B.1 and
Table B.2 are examples based on hypothetical BOP equipment system and are for illustration purposes only. Each
user of this standard should develop their own approach. They are not to be considered exclusive or exhaustive in
nature. API makes no warranties, express or implied, for reliance on or any omissions from the information
contained in this document.
WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
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Figure B.2—Example BOP Drawdown Test Worksheet for Land and Surface Offshore
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55
56
API STANDARD 53
Figure B.3—Example BOP Function Test Worksheet for Subsea
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Figure B.4—Example BOP Drawdown Test Worksheet for Subsea
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58
API STANDARD 53
Table B.1—Example Surface MEWSP Calculations Given Well and Equipment-specific Data
Actual or Calculated
Shear Value
psig (MPa)
MASP
psig (MPa)
Shearing Ratio
(SR)
Control System
Operating Pressure
psig (MPa)
2174 (14.99)
5000 (34.47)
14.64
3000 (20.68)
With Annular Open:
MEWSP = actual or calculated shear value
Example: 2174 psig (to shear pipe with the annular open)
With Annular Closed:
MEWSP = actual or calculated shear + (MASP/SR)
Example: 2174 + (5000/14.64) = 2516 psig (to shear pipe with MASP trapped under a closed annular)
NOTE 1 These equations show relative shear pressures. Accumulator calculations should use absolute pressures.
NOTE 2 These calculations are presented as examples only and are not intended to restrict the use of other methods.
Table B.2—Example Subsea MEWSP Calculations Given Well and Equipment-specific Data
Actual or Calculated
Surface Shear Pressure
psig (MPa)
MAWHP at the
Wellhead
psig (MPa)
Shearing
Ratio
(SR)
Mud Weight
Hydrostatic Pressure
psig (MPa)
Control System
Operating Pressure
psig (MPa)
2174 (14.99)
4000 (27.58)
14.64
2746 (18.93)
5000 (34.47)
With Annular Open:
MEWSP = actual or calculated surface shear value + (hydrostatic pressure/SR)
Example: 2174 + (2746/14.64) = 2361 psig to shear pipe with the annular open
With Annular Closed:
MEWSP = actual or calculated surface shear value + (MAWHP/SR)
Example: 2174 + (4000 /14.64) = 2447 psig (to shear pipe with MAWHP trapped under a closed annular)
NOTE 1 These equations show relative shear pressures. Accumulator calculations should use absolute pressures.
NOTE 2 These calculations are presented as simplified examples only and are not intended to restrict the use of other methods.
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Annex C
(normative)
Testing
Table C.1 through Table C.14 shall be conducted at the prescribed frequency utilizing the listed test acceptance
criteria.
Table C.1—Initial Function Testing, Surface BOP Stacks
System/Component
Function Test Description
Test Acceptance Criteria
Dedicated Accumulator Systems Test
Dedicated shear
accumulatorsa
Drawdown tested by operation of high-pressure
shear function(s)
Verification of intended operation may be in the
form of flowmeter volume counts (when
available), pressure testing, or other applicable
means
Verification that components actuated per
design
Final accumulator pressure greater than the
MOP to secure the well
Primary Control Systems Test
Control stationsabc
Function test of all control stations and remote
panels
Verification of intended operation
Visual verification of no leaks
BOP stack operators
and valvesa
BOP functions tested (to include ram operators,
annular operators, valves, high-pressure
circuits) at maximum pressures expected for
well control operations
Verification of intended operation may be in the
form of visual inspection, flowmeter volume
counts (when available), pressure testing, or
other applicable means
Response times to meet 5.3.6.2
Flowmeter volume counts (when available) to
be within equipment owner's criteria
Main accumulator
systema
HPU pumpsa
BOP stacka
Drawdown test per 5.3.14
Cumulative output capacity of pump systems to
be timed, charging the main accumulator after
drawdown test to system RWP
BOP to be drifted with a minimum diameter tool
or drift as determined by the equipment owner
and user’s requirements
Verification that the final accumulator pressure
is greater than the MOP specified in system
accumulator sizing
Verification that system RWP is achieved within
15 minutes
Pass completely through BOP stack after BOP
initial pressure and function testing (16A
acceptance criteria to drift within 30 minutes not
applicable)
Drill Floor Safety Valves
Valvesa
Function test
Verification of intended operation
Choke Manifold Test
Adjustable chokesa
Function test
Verification of intended operation
a
Not required for pad drilling operations when moving to subsequent wells. Additional initial function testing is required for connections where
the integrity of a pressure seal is broken.
b
A function test from a remote panel satisfies the requirement for a local function test of the hydraulic control unit.
c
Maintenance panels excluded.
59
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60
API STANDARD 53
Table C.2—Subsequent Operational Function Testing, Surface BOP Stacks
System/Component
Function Test
Description
Test Acceptance Criteria
Frequency
Dedicated Accumulator Systems Test
Drawdown test
Dedicated emergency shear
accumulators
With charging system
isolated, discharge the
volume of the greatest
consuming emergency
system mode
Accumulator pressure greater than the
MOP to secure the well
Not to exceed
180 days
Control Systems Test
BOP rams, annulars, choke
and kill valves (excluding
shear rams)
Casing shear rams, BSRs,
and blind rams
High-pressure casing shear
ram circuit and high-pressure
BSRs close circuit
Function tested from one
designated control
stationa
Control stations to be
alternated between tests
Function tested from one
designated control
stationa
Control stations to be
alternated between tests
Function tested from one
designated control
stationa
Control stations to be
alternated between tests
Drawdown tested per
5.3.14
Main accumulator system
HPU pumps
Cumulative output
capacity of pump systems
to be timed, charging the
main accumulator after
drawdown test to system
RWP
Verification of intended operation may be
by recovery of system pressure, flowmeter
readback, or other applicable means
Response times to meet 5.3.6.2
Not to exceed 7
days
Flowmeter volume counts (when available)
to be within the equipment owner's criteria
Verification of intended operation may be
by recovery of system pressure, flowmeter
readback, or other applicable means
Response times to meet 5.3.6.2
Not to exceed
21 days
Flowmeter volume counts (when available)
to be within the equipment owner's criteria
Verification of intended operation may be
by recovery of system pressure, flowmeter
readback, or other applicable means
Response times to meet 5.3.6.2
Not to exceed
90 days
Flowmeter volume counts (when available)
to be within the equipment owner's criteria
Verification that the final accumulator
pressure is greater than the MOP specified
in system accumulator sizing
Verification that system RWP is achieved
within 15 minutes
Not to exceed
180 daysb
Drill Floor Safety Valves
Valves
Function test
Verification of intended operation
Daily
Choke Manifold Test
Adjustable chokes
Function test
Verification of intended operation
Daily
a
Maintenance panels excluded.
b
Temperature variations can affect the usable volume in the accumulator system. An accumulator usable volume calculation or a drawdown
test may be used to verify usable fluid when extreme temperature variations occur at the accumulator.
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WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
61
Table C.3—Scheduled Function Testing, Surface BOP Stacks
System/Component
Function Test
Description
Test Acceptance Criteria
Frequencya
Primary Control Systems Test
UPS battery test
Two-hour UPS system
function test (the main
UPS electrical supply
isolated) with the BOP
control system powered in
routine drilling mode
Control Fluid Reservoir (if
applicable)
Control fluid reservoir
mixing operation and level
alarms
BOP stack hydraulic circuits
The integrity of the BOP
stack hydraulic circuits to
be verified with regulators
set at maximum circuit
pressure
Verification of the UPS battery system by
operation of a single BOP stack function
after two hours
Verification that appropriate visual and/or
audible alarm is received from each tank
fluid level
Verification of automatic mixing system
functionality
Visual verification of no leaks
Not to exceed
12 months
Not to exceed
12 months
Not to exceed
12 months
Test duration to be per
equipment owner
requirements
HPU pumps
a
HPU pump systems start
and stop pressures
Verification that primary pump system
automatically starts before system pressure
has decreased to 90 % of the system RWP
and automatically stops at system RWP
±2 %
Verification that the secondary pump
system automatically starts before system
pressure has decreased to 85 % of the
system RWP and automatically stops
between 95 % and 100 % of the system
RWP
Testing not to be conducted during operations.
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Not to exceed
12 months
62
API STANDARD 53
Table C.4—Initial Pressure Testing, Surface BOP Stacks
Component to be Pressure
Tested
Pressure Test—Low
Pressureac
psig (MPa)
Pressure Test—High Pressureac
Change Out of
Component, Elastomer,
or Ring Gasket
No Change Out of
Component, Elastomer,
or Ring Gasket
Annular preventerb
250 to 350 (1.72 to 2.41)
RWP of annular preventer
MASP or 70% annular
RWP, whichever is lower.
Fixed pipe, variable bore,
blind, and BSR preventersbd
250 to 350 (1.72 to 2.41)
RWP of ram preventer or
wellhead system,
whichever is lower
ITP
Choke and kill line and BOP
side outlet valves below ram
preventers (both sides)
250 to 350 (1.72 to 2.41)
RWP of side outlet valve or
wellhead system,
whichever is lower
ITP
Choke manifold—upstream of
chokese
250 to 350 (1.72 to 2.41)
RWP of ram preventers or
wellhead system,
whichever is lower
ITP
Choke manifold—downstream
of chokese
250 to 350 (1.72 to 2.41)
RWP of valve(s), line(s), or MASP for the well program,
whichever is lower
Kelly, kelly valves, drill pipe
safety valves, IBOPs
250 to 350 (1.72 to 2.41)
MASP for the well program
a
Pressure test evaluation periods shall be a minimum of five minutes.
No visible leaks.
The pressure shall remain stable during the evaluation period. The pressure shall not decrease below the intended test pressure.
b
Annular(s) and VBR(s) shall be pressure tested on the largest and smallest OD drill pipe to be used in well program.
For pad drilling operations, moving from one wellhead to another within the 21 days, pressure testing is required for pressure-containing and
pressure-controlling connections when the integrity of a pressure seal is broken.
d
For surface offshore operations, the ram BOPs shall be pressure tested with the ram locks engaged and the closing and locking pressure
vented during the initial test. For land operations, the ram BOPs shall be pressure tested with the ram locks engaged and the closing and
locking pressure vented at commissioning and annually.
c
e
Adjustable chokes are not required to be full sealing devices. Pressure testing against a closed choke is not required.
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WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
63
Table C.5—Subsequent Operational Pressure Testing, Surface BOP Stacks
Component to be
Pressure Tested
Pressure Test—Low
Pressurea
psig (MPa)
Pressure Test—High Pressurea
Frequency
Annular preventerb
250–350 (1.72–2.41)
MASP for the hole section or 70 % annular
RWP, whichever is lower
Not to exceed 21
days
BOP side outlet valves
above pipe ram preventers
(wellbore side)
250–350 (1.72–2.41)
MASP for the hole section or 70 % annular
RWP, whichever is lower
Not to exceed 21
days
BOP side outlet valves
above pipe ram preventers
(non-wellbore side)
250–350 (1.72–2.41)
MASP for the hole section
Not to exceed 21
days
Fixed and variable bore
pipe ram preventersb
250–350 (1.72–2.41)
MASP for the hole section
Not to exceed 21
days
Choke and kill line and
BOP side outlet valves
below pipe ram preventers
(both sides)
250–350 (1.72–2.41)
MASP for the hole section
Not to exceed 21
days
Choke manifold—upstream
of chokesc
250–350 (1.72–2.41)
MASP for the hole section
Not to exceed 21
days
Choke manifold—
downstream of chokesc
250–350 (1.72–2.41)
RWP of valve(s), line(s), or MASP for the
hole section, whichever is lower
Not to exceed 21
days
Kelly, kelly valves, drill pipe
safety valves, IBOPs
250–350 (1.72–2.41)
MASP for the hole section
Not to exceed 21
days
Blind and BSR preventers
250–350 (1.72–2.41)
Casing test pressure
At casing points
a
Pressure test evaluation periods shall be a minimum of five minutes.
No visible leaks.
The pressure shall remain stable during the evaluation period. The pressure shall not decrease below the intended test pressure.
b
Annular(s) and VBR(s) shall be pressure tested on the smallest OD drill pipe expected to be used in the next 21 days.
c
Adjustable chokes are not required to be full sealing devices. Pressure testing against a closed choke is not required.
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API STANDARD 53
Table C.6—Operating Chamber Pressure Testing, Surface BOP Stacks
Component to be
Pressure Tested
Pressure Test—Low
Pressure
psig (MPa)
Pressure Test—High Pressurea
Frequency
Annular preventer open
and closing operating
chambers
Not required
RWP as specified by equipment manufacturer
Every 12 months
BOP choke and kill valve
open and closing operating
chambers
Not required
RWP as specified by equipment manufacturer
Every 12 months
Ram preventer open and
closing operating
chambers
Not required
RWP as specified by equipment manufacturer
Every 12 months
Casing shear ram open
and closing operating
chambers
Not required
RWP as specified by equipment manufacturer
Every 12 months
a
b
Pressure test evaluation periods shall be a minimum of five minutes.
No visible leaks.
The pressure shall remain stable during the evaluation period. The pressure shall not decrease below the intended test pressure.
If the BOP is in operation, the test is to be conducted during the BOP next planned maintenance.
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65
Table C.7—Pre-deployment Function Testing, Subsea BOP Stacks
System/Component
Function Test Description
Test Acceptance Criteria
Secondary Control Systems
Acoustic System
ROV Intervention
Critical functions tested by activation through
acoustic control unit
Each shear ram CLOSE
One pipe ram CLOSE
Ram locks LOCK
LMRP connector UNLATCH
Verification of intended operation may be in the
form of visual inspection, flowmeter volume
count, pressure testing, or other applicable
means
Function test of critical functions through
intervention circuit
Each sealing shear ram CLOSE and LOCK
Each non-sealing shear ram CLOSE
One pipe ram CLOSE and LOCK
LMRP connector UNLATCH
Verification of intended operation may be in the
form of visual inspection, flowmeter volume
count, pressure testing, or other applicable
means
Response times to meet 6.4.6.2
Response times to meet 6.4.6.2
Emergency Control Systems
Completed in 90 seconds or lessc
Deadman circuit
testad
All modes function tested by removing electric
power and hydraulic supply to the stack
Verification of intended operation/sequence
may be in the form of visual inspection,
flowmeter volume count, pressure testing, or
other applicable means
Completed in 90 seconds or lessc
Autoshear circuit
testabd
All modes function tested by activation of trigger
Verification of intended operation/sequence
may be in the form of visual inspection,
flowmeter volume count, pressure testing, or
other applicable means
Primary Control Systems
Control stationse
Function test of all control stations and remote
panels
Positive verification of intended operation
Visual verification of no leaks
BOP stack
operators, valves,
and pods
BOP functions tested from installed pods (to
include ram operators, annular operators,
connectors, stack mounted valves, stabs,
cylinders, pod specific functions, high-pressure
circuits, secondary circuits).
Verification of intended operation may be in the
form of visual inspection, flowmeter volume
count, pressure testing, or other applicable
means
Response times to meet 6.4.6.2
Flowmeter volume count to be within
equipment owner's criteria
BOP gas bleed and
side outlet valves
Main accumulator
system
HPU pumps
BOP stack hydraulic
circuits
Valve closure to be function tested with springs
only (no hydraulic assist)
Drawdown test per 6.4.15
Cumulative output capacity of pump systems to
be timed, charging the main accumulator after
drawdown test to system RWP
The integrity of the BOP stack hydraulic circuits to
be verified at maximum pressures expected for
well control operations
Verification valve shifts to fully closed state by
visual inspection, pressure testing, flowing
through valves, or other applicable means
Verification that the final accumulator pressure
is greater than the MOP specified in system
accumulator sizing
Verification that system RWP is achieved within
15 minutes
Visual verification of no leaks
Test duration to be per equipment owner
requirements
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66
System/Component
Emergency
disconnect
sequence (dry test)
API STANDARD 53
Function Test Description
All modes function tested
Each EDS activation location function tested with
at least one mode
Emergency
disconnect
sequence (wet test)
The mode that consumes the largest volume of
hydraulic fluid function tested by activation at
control station
BOP stack
BOP to be drifted with a minimum diameter tool or
drift as determined by the equipment owner and
user's requirements
Test Acceptance Criteria
Verification at data logger that functions were
commanded per sequence
Verification at data logger that functions were
commanded per sequence
Verification of intended operation may be in the
form of visual inspection, flowmeter volume
count, pressure testing, or other applicable
means
Pass completely through BOP stack after BOP
pre-deployment pressure and function testing
(API 16A acceptance criteria to drift within 30
minutes not applicable)
a
Securing the well includes closing rams, valves, and locks and does not include disconnects or other functions that may subsequently be
employed after the well has been secured.
b
Autoshear systems that are initiated by removal of electric power and hydraulic supply to the stack do not require a separate test from the
deadman system.
c
Minimal time requirement to secure the wellbore does not include functions after well has been secured.
d
Power fluid may be supplied from surface accumulators or an alternative source.
e
Maintenance panels excluded.
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67
Table C.8—Initial Function Testing, Subsea BOP Stacks
System/Component
Function Test Description
Test Acceptance Criteria
Secondary Control Systems
Acoustic system
Close one ram BOP
ROV intervention
Close one ram BOP
Verification of intended operation may be in the
form of flowmeter volume count, pressure testing,
or other applicable means
Response times to meet 6.4.6.2
Verification of intended operation may be in the
form of flowmeter volume count, pressure testing,
or other applicable means
Response times to meet 6.4.6.2
Emergency Control Systems
Dedicated emergency
accumulators
One mode function tested by removing
control and hydraulic supply to the
activation device
Deadman circuit test
Completed in 90 seconds or lessab
Positive verification of intended operation may be
in the form of flowmeter volume count, pressure
testing, or other applicable means
Verification that components actuated per design
Final accumulator pressure greater than the MOP
to secure the well
Primary Control Systems
BOP rams, annulars,
choke and kill valves
BOP functions tested from the control
stations through the installed podsc
Verification of intended operation may be by
recovery of system pressure, flowmeter readback,
or other applicable means
Response times to meet 6.4.6.2
Flowmeter volume counts to be within equipment
owner's criteria
Verification of intended operation may be by
recovery of system pressure, flowmeter readback,
or other applicable means
Response times to meet 6.4.6.2
Flowmeter volume counts to be within equipment
owner's criteria
High-pressure casing
shear rams and highpressure BSRs close
circuits
Function tested from installed pods from
designated control stationsa
Main accumulator system
(only required on systems
that rely on LMRP
accumulators to meet
sizing requirements)
Drawdown test per 6.4.15
Verification that the final accumulator pressure is
greater than the MOP specified in system
accumulator sizing
BOP stack
BOP to be drifted with a minimum
diameter tool or drift as determined by
the equipment owner and user's
requirements
Pass completely through BOP stack after BOP
initial pressure and function testing (API 16A
acceptance criteria to drift within 30 minutes not
applicable)
Drill Floor Safety Valves
Valves
Function test
Verification of intended operation
Choke Manifold
Adjustable chokes
Function test
Verification of intended operation
a
Securing the well includes closing rams, valves, and locks and does not include disconnects or other functions that may subsequently be
employed after the well has been secured.
b
Minimal time requirement to secure the wellbore does not include functions after well has been secured.
c
Maintenance panels excluded.
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68
API STANDARD 53
Table C.9—Subsequent Operational Function Testing, Subsea BOP Stacks
System/Component
Function Test Description
Test Acceptance Criteria
Frequency
Acoustic
Battery check
Verification of communication
Not to exceed 21
days
Emergency Control Systems
Drawdown test
Dedicated emergency
accumulators
With charging system isolated,
discharge the volume of the
greatest consuming emergency
system mode
Accumulator pressure greater than the
MOP to secure the well
Not to exceed 180
days
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Secondary Control Systems
Primary Control Systems
BOP rams, annulars,
and choke and kill
valves (excluding
shear rams)
Function tested through one pod
from one designated control stationa
Pods to be alternated between tests
Control stations to be alternated
according to equipment owner's
schedule
Response times to meet 6.4.6.2
High-pressure casing
shear ram circuit and
high-pressure BSRs
close circuit
Main accumulator
system
HPU pumps
Not to exceed 7
days
Flowmeter volume counts to be within
equipment owner's criteria
Function tested through one pod
from one designated control stationa
Casing shear rams
and BSRs
Verification of intended operation may
be by recovery of system pressure,
flowmeter readback, or other
applicable means
Pods to be alternated between tests
Control stations to be alternated
according to equipment owner's
schedule
Verification of intended operation may
be by recovery of system pressure,
flowmeter readback, or other
applicable means
Response times to meet 6.4.6.2
Not to exceed 21
days
Flowmeter volume counts to be within
equipment owner's criteria
Function tested through one pod
from one designated control stationa
Pods to be alternated between tests
Verification of intended operation may
be by recovery of system pressure,
flowmeter readback, or other
applicable means
Control stations to be alternated
according to equipment owner's
schedule
Response times to meet 6.4.6.2
Drawdown test per 6.4.15
Verification that the final accumulator
pressure is greater than the MOP
specified in system accumulator sizing
Not to exceed 90
days
Flowmeter volume counts to be within
equipment owner's criteria
Cumulative output capacity of pump
systems to be timed, charging the
main accumulator after drawdown
test to system RWP
Verification that system RWP is
achieved within 15 minutes
Not to exceed 180
daysb
Drill Floor Safety Valves
Valves
Function test
Verification of intended operation
Daily
Choke Manifold
Adjustable chokes
Function test
Verification of intended operation
Daily
a
Maintenance panels excluded.
b
Temperature variations can affect the usable volume in the accumulator system. An accumulator usable volume calculation or a drawdown
test may be used to verify usable fluid when extreme temperature variations occur at the accumulator.
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Table C.10—Scheduled Function Testing, Subsea BOP Stacks
System/Component
Function Test Description
Test Acceptance Criteria
Frequencya
Secondary Control Systems
ROV
Function test of all functions
through intervention circuit and
valves
Testing to be conducted during predeployment testing with BOP on
surface
Positive verification of intended
operation may be in the form of visual
inspection, flowmeter gallon count,
pressure testing, or other applicable
means
Not to exceed 12
months
Response times to meet 6.4.6.2
Primary Control Systems
EDS
Verification at data logger that
functions were commanded per
sequence
The mode that consumes the
largest volume of hydraulic fluid
function tested by activation at
control station
Positive verification of intended
operation may be in the form of ROV
inspection, flowmeter gallon count,
pressure testing, or other applicable
means
Testing to be conducted with BOP
latched to the wellhead
UPS battery test
Two-hour UPS system function test
(the main UPS electrical supply
isolated) with the BOP control
system powered in routine drilling
mode
Verification of the UPS battery system
by operation of a single BOP stack
function after two hours
Not to exceed 5
years
Not to exceed 12
months
Testing to be conducted with BOP
on surface
Control fluid reservoir
(if applicable)
HPU pumps
a
Control fluid reservoir mixing
operation and level alarms
HPU pump systems start and stop
pressures
Verification that appropriate visual
and/or audible alarm is received from
each tank fluid level
Verification of automatic mixing system
functionality
Verification that primary pump system
automatically starts before system
pressure has decreased to 90 % of the
system RWP, and automatically stops
at system RWP ±2 %
Verification that the secondary pump
system automatically starts before
system pressure has decreased to
85 % of the system RWP and
automatically stops between 95 % and
100 % of the system RWP
Testing not to be conducted during operations.
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Not to exceed 12
months
Not to exceed 12
months
70
API STANDARD 53
Table C.11—Pre-deployment Pressure Testing, Subsea BOP Stacks
Pressure Test—High Pressurea
Component to be Pressure
Tested
Pressure Test—Low Pressurea
psig (MPa)
Change-out of
Component,
Elastomer, or Ring
Gasket
No Change-out of
Component,
Elastomer, or Ring
Gasket
Annular preventerb
250–350 (1.72–2.41)
RWP of annular
preventer
MAWHP or 70 %
annular RWP,
whichever is lower
BOP side outlet valves below
annular and above ram preventers
(wellbore side)
250–350 (1.72–2.41)
RWP of annular
preventer
MAWHP or 70 %
annular RWP,
whichever is lower
BOP side outlet valves below
annular and above ram preventers
(non-wellbore side)
250–350 (1.72–2.41)
RWP of ram preventers
PDTP or 5000 psig,
whichever is higher
Fixed pipe, variable bore, and
BSR preventersbc
250–350 (1.72–2.41)
RWP of ram preventer
PDTP or 5000 psig,
whichever is higher
LMRP and wellhead connectors
250–350 (1.72–2.41)
Same as BOP above
connector
Same as BOP above
connector
Choke and kill line and BOP side
outlet valves below ram
preventers (both sides)
250–350 (1.72–2.41)
RWP of ram preventers
PDTP or 5000 psig,
whichever is higher
a
Pressure test evaluation periods shall be a minimum of five minutes.
No visible leaks.
The pressure shall remain stable during the evaluation period. The pressure shall not decrease below the intended test pressure.
b
Annular(s) and VBR(s) shall be pressure tested on the largest and smallest OD drill pipe to be used in well program.
c
Ram-type BOPs shall be pressure tested with the locks engaged and the closing and locking pressure vented.
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Table C.12—Initial Pressure Testing, Subsea BOP Stacks
Component to be Pressure
Tested
Pressure Test—Low Pressurea
psig (MPa)
Pressure Test—High Pressurea
Annular preventerb
250–350 (1.72–2.41)
MAWHP or 70 % annular RWP, whichever is lower
BOP side outlet valves below
annular and above ram
preventers (wellbore side)
250–350 (1.72–2.41)
MAWHP or 70 % annular RWP, whichever is lower
BOP side outlet valves below
annular and above ram
preventers (non-wellbore side)
250–350 (1.72–2.41)
MAWHP for the well program
Fixed pipe and variable bore,
ram preventersbc
250–350 (1.72–2.41)
MAWHP for the well program
LMRP and wellhead connectors
250–350 (1.72–2.41)
Same as BOP above connector
Choke and kill line and BOP side
outlet valves below ram
preventers (both sides)
250–350 (1.72–2.41)
MAWHP for the well program
Choke manifold—upstream of
chokesde
250–350 (1.72–2.41)
MAWHP for the well program
Choke manifold—downstream of
chokesde
250–350 (1.72–2.41)
RWP of valve(s), line(s), or MAWHP for the well
program, whichever is lower
Kelly, kelly valves, drill pipe
safety valves, IBOPse
250–350 (1.72–2.41)
MAWHP for the well program
a
Pressure test evaluation periods shall be a minimum of five minutes.
No visible leaks.
The pressure shall remain stable during the evaluation period. The pressure shall not decrease below the intended test pressure.
b
Annular(s) and VBR(s) shall be pressure tested on the smallest OD drill pipe to be used in the hole section.
c
Ram-type BOPs shall be pressure tested with the locks engaged and the closing and locking pressure vented.
d
Adjustable chokes are not required to be full sealing devices. Pressure testing against a closed choke is not required.
e
Pressure testing can be conducted before the BOP is latched to the wellhead.
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72
API STANDARD 53
Table C.13—Subsequent Operational Pressure Testing, Subsea BOP Stacks
Component to be Pressure
Tested
Pressure Test—Low
Pressurea
psig (MPa)
Pressure Test—High Pressurea
Frequency
Annular preventerb
250–350 (1.72–2.41)
MAWHP or 70 % annular RWP,
whichever is lower
Not to exceed 21
days
BOP side outlet valves above
pipe ram preventers (wellbore
side)
250–350 (1.72–2.41)
MAWHP or 70 % annular RWP,
whichever is lower
Not to exceed 21
days
BOP side outlet valves above
pipe ram preventers (nonwellbore side)
250–350 (1.72–2.41)
MAWHP for the hole section
Not to exceed 21
days
Fixed and variable bore pipe
ram preventersb
250–350 (1.72–2.41)
MAWHP for the hole section
Not to exceed 21
days
Choke and kill line and BOP
side outlet valves below pipe
ram preventers (both sides)
250–350 (1.72–2.41)
MAWHP for the hole section
Not to exceed 21
days
Choke manifold—upstream of
chokesc
250–350 (1.72–2.41)
MAWHP for the hole section
Not to exceed 21
days
Choke manifold—downstream
of chokesc
250–350 (1.72–2.41)
RWP of valve(s), line(s), or
MAWHP for the hole section,
whichever is lower
Not to exceed 21
days
Kelly, kelly valves, drill pipe
safety valves, IBOPs
250–350 (1.72–2.41)
MAWHP for the hole section
Not to exceed 21
days
BSR preventers
250–350 (1.72–2.41)
Casing test pressure
At casing points
a
b
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c
Pressure test evaluation periods shall be a minimum of five minutes.
No visible leaks.
The pressure shall remain stable during the evaluation period. The pressure shall not decrease below the intended test pressure.
Annular(s) and VBR(s) shall be pressure tested on the smallest OD drill pipe expected to be used in the next 21 days.
Adjustable chokes are not required to be full sealing devices. Pressure testing against a closed choke is not required.
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WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
73
Table C.14—Operating Chamber Pressure Testing, Subsea BOP Stacks
Component to be Pressure Tested
Pressure Test—Low
Pressure
psig (MPa)
Pressure Test—High
Pressurea
Frequencyb
Annular preventer open and closing
operating chambers
Not required
RWP as specified by equipment
manufacturer
Every 12 months
LMRP connector latch and unlatch
operating chambers
Not required
RWP as specified by equipment
manufacturer
Every 12 months
BOP choke and kill valve open and
closing operating chambers
Not required
RWP as specified by equipment
manufacturer
Every 12 months
Ram preventer open and closing
operating chambers
Not required
RWP as specified by equipment
manufacturer
Every 12 months
Casing shear ram open and closing
operating chambers
Not required
RWP as specified by equipment
manufacturer
Every 12 months
Wellhead connector latch and unlatch
operating chambers
Not required
RWP as specified by equipment
manufacturer
Every 12 months
a Pressure test evaluation periods shall be a minimum of five minutes.
No visible leaks.
The pressure shall remain stable during the evaluation period. The pressure shall not decrease below the intended test pressure.
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b If the BOP is in operation, the test is to be conducted when the BOP is retrieved to surface for the next planned maintenance.
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Annex D
(normative)
Failure Reporting
D.1 Equipment Owner’s Requirements
D.1.1
The equipment owner shall maintain a record of BOP system failures.
D.1.2
The failure report shall include, as a minimum:
a) The name of the equipment owner;
b) The name and location of the rig;
c) The name of the equipment owner’s primary contact (from whom additional information may be requested, if
necessary);
d) A reference number for the report;
e) A clear concise description of the event;
f)
A clear description of the component concerned, including part number, serial number, size, and pressure
ratings;
g) The root cause if the equipment owner’s SME (subject matter expert) can confidently state the root cause of
the event.
D.1.3
An RCFA (root cause failure analysis) shall be conducted when:
a) There is a loss of a well barrier;
b) There is an unplanned BOP/LMRP recovery;
c) The failure is classified as reoccurring;
d) The equipment owner’s SME is not able to confidently determine the cause.
D.2 Equipment Manufacturer’s Requirements
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D.2.1 The recipient of the reports (either the equipment manufacturer or the system integrator) shall alert all users
of the reported component if his records suggest that an event is reoccurring across the industry. The recipient shall
initiate an RCFA with representatives of the applicable equipment owners invited to attend/partake.
D.2.2 The equipment manufacturer shall follow the requirements of API 16A or other relevant specification in
regard to design change notifications.
D.2.3 Significant problems experienced with BOP equipment noted during its manufacture, testing, or use shall
be formally communicated to the individual or group within the manufacturer's organization responsible for the
design and specification documents.
D.2.3.1 The manufacturer shall have a written procedure that describes forms and procedures for making this type
of communication.
D.2.3.2 The manufacturer shall maintain records of progressive design, material changes, or other corrective
actions taken for each model and size of blowout prevention equipment.
74
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WELL CONTROL EQUIPMENT SYSTEMS FOR DRILLING W ELLS
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D.2.4 All significant problems experienced with blowout prevention equipment shall be reported in writing to every
equipment owner of the blowout prevention equipment within three weeks after the occurrence.
D.2.5 The manufacturer shall communicate design changes resulting from a malfunction or failure to every
equipment owner using the affected equipment. That notice shall be within 14 days after the design change.
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Bibliography
[1] API Recommended Practice 2INT-MET, Interim Guidance on Hurricane Conditions in the Gulf of Mexico
[2] API Recommended Practice 2SK, Design and Analysis of Stationkeeping Systems for Floating Structures
[3] API Specification 5L, Specification for Line Pipe
[4] API Recommended Practice 16ST, Coiled Tubing Well Control Equipment Systems
[5] API Recommended Practice 59, Recommended Practice for Well Control Operations
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[6] API Recommended Practice 75, Development of a Safety and Environmental Management Program for
Offshore Operations and Facilities
[7] API RP 49, Recommended Practice for Drilling and Well Servicing Operations Involving Hydrogen Sulfide
[8] API 17TR15, API 17H, Hydraulic Interfaces for Hot Stabs
[9] ASME Boiler and Pressure Vessel Code (BPVC), Section VIII: Pressure Vessels
[10] ASME B16.5, Pipe Flanges and Flanged Fittings: NPS 1/2 through NPS 24 Metric/Inch Standard
[11] SPE-20430-PA, Mud/Gas Separator Sizing and Evaluation
76
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Product No. G05305
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