api 53 changes - 4th edition vs. 3rd edition.pdf
TRANSCRIPT
Differences between RP 53
and Standard 53 (S53)
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25, August 2010 Assignment S53 RP53
Certification
API RP 53 should form the basis for certification and verification requirements for BOP equipment and other components of the BOP stack such as control panels, pods, accumulators, and choke/kill lines.
A planned maintenance system, with equipment identified, tasks specified, and the time intervals between tasks stated, shall be employed on each rig. 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 the rig or service. 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 the components meets or exceeds the OEM specifications. Certification is mentioned 5 times in S53 and used in sections: 6.5.10.4 7.6.11.4
A planned maintenance system, with equipment identified, tasks specified, and the time intervals between tasks stated, should be employed on each rig. Records of maintenance performed and repairs made should be maintained on file at the rig site or readily available for the applicable BOP equipment. Certification is mentioned 8 times in RP53 and used in sections: 17.13.2 17.3.8 18.13.2 18.3.8
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25, August 2010 Assignment S53 RP53
Shear ram configuration / spacing
Given today’s shearing capability, industry agrees that two shear rams (SR), one of which can seal, are required in order to ensure that the stack will be able to shear the drill pipe in the event a tool joint is across one of the SRs. Since this configuration may reduce the redundancy available for more frequently used stack functions (i.e., pipe rams), industry is developing alternate options. For example, shear ram technology that is capable of shearing both tool joint and drill pipe with one ram is under consideration. If this technology becomes commercially available, industry proposes the option of returning to a single shear ram. This provides additional pipe ram capability to close on the wide range of pipe sizes used in drilling and completion operations. Additional time is needed to determine if the dual SR requirement would improve safety on moored rig operations.
6.1.2.7 thru 6.1.2.13 address the requirements for Blind and BSR's for surface BOP operations. 7.1.3.1.6 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. 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 7.1.3.2. 7.1.3.2 identifies specific items that need to be included in the Risk Assessment before removal of the second shearing ram is removed from the BOP Arrangement. 7.3.8 Dedicated Accumulator Systems The dedicated accumulators are supplied by the main accumulator system or a dedicated pump/accumulator supply, but shall not be affected if the main supply is depleted or lost. Sections 6.5.10.7 and 7.6.11.7 specifically address the use of BSR's and CSR's.
N/A for surface. 7.3.2. d – Blind Shear rams are used in place of blind rams.
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25, August 2010 Assignment S53 RP53
ROV Intervention Industry agrees with the minimum requirement for ROV intervention capabilities.
Critical functions for ROV intervention identified 7.3 Discrete Hydraulic Control Systems for Subsea BOP Stacks 7.3.1.5 The minimum required components of the BOP control system shall include the following: j) emergency systems; & k) secondary control systems. 7.3.17 Emergency Disconnect System/Sequence 7.3.17.1 An emergency disconnect sequence (EDS) shall be available on all subsea BOP stacks that are run from a dynamically positioned vessel. A EDS is optional for moored vessels. 7.3.18 Autoshear System 7.3.19 Deadman System 7.3.20 Secondary Control System 7.3.20.1 ROV Intervention 7.3.20.2 Acoustic Control Systems (optional) 7.4 Electro-hydraulic and Multiplex Control Systems for Subsea BOP Stacks 7.4.1.5 The minimum required components of the BOP control system shall include the following: k) emergency systems; l) secondary control systems 7.4.13 Emergency Disconnect System/Sequence 7.4.14 Autoshear System 7.4.15 Deadman System 7.4.16 Secondary Control Systems 7.4.16.1 ROV Intervention 7.4.16.2 Acoustic Control System
N/A
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25, August 2010 Assignment S53 RP53
Arming / Disarming secondary controls
Industry recommends that autoshear and deadman are armed at all times (after latch up) and MOC process is required to disarm.
7.3.18.3 The autoshear system shall be armed while the BOP stack is latched onto a wellhead. A documented MOC shall be required to disarm the system unless covered in equipment owner’s standard operating procedures (SOP). 7.3.19.3 The deadman system shall be armed while the BOP stack is latched onto a wellhead. A documented MOC shall be required to disarm the system unless covered in equipment owner’s SOP. 7.4.14.3 The Autoshear system shall be armed while the BOP stack is latched onto a wellhead. A documented MOC shall be required to disarm the system unless covered in equipment owner’s SOP. 7.4.15.3 The deadman system shall be armed while the BOP stack is latched onto a wellhead. A documented MOC shall be required to disarm the system unless covered in equipment owner’s SOP.
Deadman Autoshear is optional.
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25, August 2010 Assignment S53 RP53
Intervention ports
Industry recommends standardization on API 17H high-flow single-port stabs.
7.3 Discrete Hydraulic Control Systems for Subsea BOP Stacks 7.3.20 Secondary Control System 7.3.20.1 ROV Intervention 7.3.20.1.1 The BOP stack shall be equipped with ROV intervention equipment that at a minimum allows the operation of the critical functions (each shear ram, one pipe ram, ram locks, and unlatching of the LMRP connector). 7.3.20.1.2 Hydraulic fluid can be supplied by the ROV, stack mounted accumulators (which may be a shared system), or an external hydraulic power source that shall be maintained at the well site. The source of hydraulic fluid shall have necessary pressure and flow rate to operate these functions. 7.3.20.1.3 All critical functions shall be fitted with single-port docking receptacles designed in accordance with API 17H. 7.3.20.1.4 If multiple receptacle types are used, a means of positive identification of the receptacle type and function shall be required. 7.3.20.1.5 Frequency of testing and acceptance criteria shall be in accordance with Table 6 and Table 7. 7.3.20.1.6 All critical functions shall meet the closing time requirements in 7.3.10.4.
N/A
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25, August 2010 Assignment S53 RP53
Intervention ports (continued)
Industry recommends standardization on API 17H high-flow single-port stabs.
7.4 Electro-hydraulic and Multiplex Control Systems for Subsea BOP Stacks 7.4.16 Secondary Control Systems 7.4.16.1 ROV Intervention 7.4.16.1.1 The BOP stack shall be equipped with ROV intervention equipment that at a minimum allows the operation of the critical functions (each shear ram, one pipe ram, ram locks, and unlatching of the LMRP connector). 7.4.16.1.2 Hydraulic fluid can be supplied by the ROV, stack mounted accumulators (which may be a shared system) or an external hydraulic power source that shall be maintained at the well site. The source of hydraulic fluid shall have necessary pressure and flow rate to operate these functions. 7.4.16.1.3 All critical functions shall be fitted with single-port docking receptacles designed in accordance with API 17H. 7.4.16.1.4 If multiple receptacle types are used, a means of positive identification of the receptacle type and function shall be required . 7.4.16.1.5 Frequency of testing and acceptance criteria shall be in accordance with Table 6 and Table 7. 7.4.16.1.6 All critical functions shall meet the closing time requirements in 7.4.6.5.4.
N/A
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25, August 2010 Assignment S53 RP53
ROV performance standards
Using ROV intervention to test BOP critical functions subsea is currently achievable, but should not be limited to direct ROV-powered function. Testing may also be accomplished through ROV facilitation such as piloting, hot line, etc.
Along with the text within the document, the requirements are summarized in tables 6, 7, 8, 9 &10 for pre-deployment, initial and subsequent testing requirements for primary, secondary and emergency systems. Frequency of testing and acceptance criteria included.
N/A
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25, August 2010 Assignment S53 RP53
ROV interface below lowest ram
Industry recognizes the need for ROV access to the BOP (i.e., rams). However, installing the interface below the lowest ram is not advisable. Risks significantly outweigh benefits.
N/A N/A
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25, August 2010 Assignment S53 RP53
Surface / Subsea testing of ROV and BOP stack capabilities
Industry recommends surface testing, (function and pressure) of all BOP and ROV intervention functions to verify the functionality of the system on surface. Industry recommends subsea testing only the shear rams using the ROV intervention port after land out of BOP on all new wells (facilitated by an ROV). Unlatch functions should not be tested subsea.
Along with the text within the document, the requirements are summarized in tables 6, 7, 8, 9 &10 for pre-deployment, initial and subsequent testing requirements for primary, secondary and emergency systems. Frequency of testing and acceptance criteria included.
N/A
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25, August 2010 Assignment S53 RP53
Subsea testing
Industry recommends the following testing requirements: Conduct a full surface function and pressure test prior to running the BOP stack to simulate (if equipped): 1) unintended disconnect of LMRP 2) loss of surface control of the subsea BOP stack 3) Emergency disconnect sequence Industry proposes continued study on the value of performing subsea testing of the emergency control systems.
Along with the text within the document, the requirements are summarized in tables 6, 7, 8, 9 &10 for pre-deployment, initial and subsequent testing requirements for primary, secondary and emergency systems. Frequency of testing and acceptance criteria included.
Tables 3 & 4 specific to pressure and function testing, predeployment, upon installation and subsequent. Nothing on requirements for testing secondary or emergency systems.
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25, August 2010 Assignment S53 RP53
Electronic log from BOP control system
Industry agrees that the electronic log contains valuable information and should be considered as an industry standard on deepwater operations. This data regarding BOP operations should be retrievable for preservation and analysis via a “black box”, or transmitted to an onshore location, or captured by an alternative data logging method.
Data Acquisition and remote monitoring for Discreet Hydraulic systems is not required based on that there is not any type of specification that exist on the design and output needs for such a systems. This was passed onto Spec 16D for their consideration. 7.4 Electro-hydraulic and Multiplex Control Systems for Subsea BOP Stacks 7.4.10 Data Acquisition and Remote Monitoring 7.4.10.1 Data shall be captured or logged during the course of well drilling operations. 7.4.10.2 Data captured shall include as a minimum the time and date stamp, solenoid functions energized, regulator and read-back pressures, and subsea accumulator pressures. 7.4.10.3 Data shall be retained in a manner that is easily retrievable (e.g. transmission to shore monitoring, backup).
Data acquisition is only required in terms of capturing test data in the testing sections of subsea. (17.3.7 and 18.3.7 of RP53)
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25, August 2010 Assignment S53 RP53
Moored rigs and secondary controls
Industry recommends that moored vessels have at least a deadman emergency system and one secondary control system (e.g., ROV). NOTE: Industry recommends that DP rigs have one secondary control system and an EDS, autoshear, and deadman emergency system.
All that applies to DP rig operations apply to moored rig operations with the excempt of the requirement to have an active EDS and the ability to be able to perform a risk assessment for the option of operating with only one BSR in a subsea stack. Otherwise, two shearing rams, at least one capable of sealing, is required.
N/A
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Let’s look at the differences
between RP53 and S53
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RP 53 vs. S53
• Changed document from Recommended Practice to
Standard.
• Introduced the first upstream Standard, that was neither an
Recommended Practice or Specification.
• Shall vs. Should
• RP53 = 50 vs. 635
• Standard 53 = +870 vs. 105
• A complete change in format.
• In place of long paragraphs, the document is broken down into
more succinct language that is easier to measure and
understand what the requirements are.
• Includes language on competency in training, procedures
and operations.
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S53
• A complete rearrangement of the document took place.
• Sections 1 thru 5 in S53 are common to both Surface and
Subsea Operations.
• Sections 4 & 5 - Diverter Systems are addressed in RP-64 and
removed from this document so as not to cause inconsistency
between the documents.
• Sections 21 & 22 – Pipe Stripping Arrangements are
addressed in RP-59 and removed from this document as it
was inappropriate to exist in this Standard and would not
cause inconsistency between documents.
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S53
• Section 6 is specific to Surface BOP Systems – making it
easier to reference for the user to look only into the section
that has applications to their specific operation.
• Section 7 is specific to Subsea BOP Systems. In the control
systems sub-section, it is broken down to direct hydraulic and
MUX control systems.
• At the end of sections 6 and 7, the entire last sub-section is
dedicated to Shearing Considerations.
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S53 (Surface and Subsea)
• Clarification of the drawdown testing requirements and
differences between Specification 16D and this Standard.
(New language)
NOTE 1 When performing the accumulator drawdown test, wait a minimum of one
hour from the time you initially charged the accumulator system from
precharge pressure to operating pressure. Failure to wait sufficient time may
result in a false positive test.
NOTE 2 Because it takes time for the gas in the accumulator to warm up after
performing all of the drawdown test functions, you should wait 15 minutes
after recording the pressure, if the pressure was less than 200 psi (1.38 MPa)
above the precharge 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 200 psi (1.38 MPa) above precharge pressure has not
been reached after 15 minutes you may have to wait an additional 15 minutes
due to ambient temperatures negatively affecting the gas properties. After 30
minutes from the time the final pressure was recorded, if the 200 psi (1.38
MPa) above precharge has not been reached, then it will be necessary to
bleed down the system and verify precharge pressures and volume
requirements for the system.
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S53
• Incorporated the affects of negative pressure on BOPE, in
subsea applications.
• Identified “performance based maintenance” as an alternative
to “scheduled based maintenance”.
• For subsea operations, two BOP’s on the rig is becoming more
common. Scheduled based maintenance is less effective since
systems are not seeing equal time of operation.
• Conditions may not have been the same either so, condition
based or performance based maintenance may be the best
indicator of the type and frequency of maintenance to be
performed.
• Greater emphasis on communications between equipment
owner and OEM (w.r.t. communicating failure reports –
Annex B).
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S53
TERMS, DEFINITIONS AND ABBREVIATIONS
• Clearly defined what a BOP is and isn’t (new language)
– blowout preventer BOP - Equipment installed on the wellhead
or wellhead assemblies to contain wellbore fluids, either in the
annular space between the casing and the tubular’s, or in an
open hole during well drilling, completion and testing operations.
Note: A Blowout Preventer is not: a gate valve(s), workover control
package, Subsea Shut‐in Device (SSID or SID), Well Control
Components (per API RP16ST), Intervention Control Packages,
Diverters, Rotating Heads or Rotating Circulating Devices,
Capping Stack, Snubbing or Stripping packages.
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S53
TERMS, DEFINITIONS AND ABBREVIATIONS
• More consistent use of MASP and its applicability to BOP
operations.
– maximum anticipated surface pressure (MASP) - Is a design
load that represents the maximum pressure that may occur in
the well during the construction of the well. As with land and
shelf wells, it is a surface pressure. (Same as RP - 96)
• More consistent use of MASP & MAWP and their applicability
to subsea BOP operations.
– maximum anticipated wellhead pressure (MAWP) - The
highest pressure predicted to be encountered at the wellhead in
each hole section of a subsea well. (Same as RP - 96)
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S53
TERMS, DEFINITIONS AND ABBREVIATIONS
• New definition added for shearing considerations in drilling
operations.
– maximum expected wellhead shear pressure (MEWSP) - The
expected pressure at the wellhead for a given hole section, a
specific shear pressure requirement, specific operating piston
design, and drill pipe material specifications, to achieve shearing
at MASP (surface), MAWP (subsea) or other pressure limiting
value.
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S53
• Expanded tables for testing requirements, acceptance criteria
and frequency (for surface and subsea applications).
• Clarification on the uses of API 16D hoses (gas & flame
requirements) as they relate to BOP controls and service
loops.
• Lines where hydrocarbons can be introduced and permeate
through the line structure are required to meet API Spec 16C fire
testing requirements. Those lines that are incapable of getting
hydrocarbons introduced are not required to meet the fire
requirements of Spec 16C.
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S53
• Enhanced subsea testing requirements (added riser recoil,
Emergency and Secondary Systems Tests)
• Considered all JITF and past JIP Reliability Study
recommendations to API
• JITF recommendations were considered.
• ROV standardization (17H High Flow and min. pipe sizing)
• Identified minimal functions required for ROV interfacing
• Included requirements for 20K, 25K and 30K systems
• Defined BOP Classifications based on the quantity of rams
and annulars for well control and emergency rams installed.
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RP 53 vs. S53 Language for surface (Sections
17.10.3 vs. 6.5.7.3)
17.10.3 MAJOR INSPECTIONS
After every 3-5 years of service, the BOP stack, choke manifold, and diverter components
should be disassembled and inspected in accordance with the manufacturer’s guidelines.
Elastomeric components should be changed out and surface finishes should be examined for
wear and corrosion. Critical dimensions should be checked against the manufacturer’s
allowable wear limits. Individual components can be inspected on a staggered schedule.
A full internal and external inspections of the flexible choke and kill lines should be performed
in accordance with the equipment manufacturer’s guidelines.
6.5.7.3 Periodic Maintenance and Inspection
6.5.7.3.1 Well control system components shall be inspected at least every 5 years in
accordance with equipment owner's PM program and the manufacturer’s guidelines.
Individual components (e.g. ram bonnets, valve actuators) can be inspected on a staggered
schedule.
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RP 53 vs. S53 Language for surface (Sections
17.10.3 vs. 6.5.7.3)
6.5.7.3 Periodic Maintenance and Inspection (cont’d)
6.5.7.3.2 As an alternative to a schedule-based inspection program, a rig-specific inspection frequency can
vary from a schedule-based PM program if the equipment owner collects and analyzes condition-based data
(including performance data) to justify a different frequency. This alternative may include trending, dynamic
vs. static seals, corrosion resistant alloy inlays in sealing surfaces, resilient vs. metal-to-metal seals,
replaceable wear plates, etc.
6.5.7.3.3 For schedule- and condition-based inspection programs, certain equipment shall undergo a
critical inspection (internal/external visual, dimensional, NDE, etc.). This inspection shall include shear
blades, bonnet bolts (or other bonnet/door locking devices), ram shaft button/foot, welded hubs, ram cavities,
and ram blocks. The actual dimensions shall be verified against the manufacturer’s allowable tolerances.
6.5.7.3.4 Inspections shall be performed by a competent person(s).
6.5.7.3.5 Consider replacing elastomeric components and checking surface finishes for wear and corrosion
during these inspections.
6.5.7.3.6 Documentation of all repairs and remanufacturing shall be maintained in accordance with 6.5.9.
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RP 53 vs. S53 Language for surface (Sections 17.11.1 vs.
6.5.8.1)
17.1 1.1 INSTALLATION, OPERATION, AND MAINTENANCE
MANUALS
Manufacturer’s installation, operation, and maintenance (IOM) manuals
should be available on the rig for all the BOP equipment installed on
the rig.
6.5.8.1 Installation, Operation, and Maintenance Manuals
Rig-specific procedures shall be developed for the installation,
operation, and maintenance (IOM) of BOP’s for the specific well and
environmental conditions. The IOM manuals shall be available on the rig
for all BOP equipment installed on the rig.
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RP 53 vs. S53
• One of the major differences between the two documents is
the method that segregates BOP equipment for well control
operations and those for emergency operations.
• Well Control – primary and secondary control systems, rams and annular
requirements.
• Emergency Systems – use of BSR and CSR, emergency control system
requirements (control system requirements), use of dedicated
accumulators, etc.
• The well control and emergency systems are unequal in the ways
that they are tested, maintained and managed, (for both surface and
subsea).
• Drawdown test 17.7.1 vs. 6.5.6.2
• 17.7.1 requires all rams and annulars for the test.
• 6.5.6.2 requires the four smallest ram annular and largest
annular volumes, for the test.
• Deadman / Autoshear Tests
• RP53 silent on the discussion
• S53 – Sections 7.3.8, 7.3.18, 7.3.19,7.3.20 and Tables 6 & 7.
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RP 53 vs. S53 - Shearing
References to Shearing (Surface)
• RP53 – Silent on the subject.
• 6.3.9.3 Rapid discharge for dedicated shear systems shall
take into account temperature effects on the precharge gas
(see Annex C).
• 6.3.9.5 The precharge pressure calculations shall take into
account the well-specific conditions (e.g. drill
• pipe shear pressure, temperature, etc.).
• 6.3.9.6 The design of the BOP, mechanical properties of drill
pipe and wellbore pressure may necessitate
• higher closing pressures for shear operations.
• 6.5.10 – Shearing Considerations (whole subsection)
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RP 53 vs. S53 - Pump Systems (same for Surface &
Subsea)
• 12.4.3 Each pump system should provide a discharge pressure at least equivalent to the BOP
control system working pressure. Air pumps should be capable of charging the accumulators to the
system working pressure with 75 psi (0.52 MPa) minimum air pressure supply.
• 12.4.1 A pump system consists of one or more pumps. Each pump system (primary and secondary)
should have independent power sources, such as electric or air. Each pump system should have
sufficient quantity and sizes of pumps to satisfactorily perform the following: With the accumulators
isolated from service, the pump system should be capable of closing the annular BOP (excluding the
diverter)o n the minimum size drill pipe being used, open the hydraulically operated choke valve(s),
and provide the operating pressure level recommended by the annular BOP manufacturer to effect a
seal on the annulus within two minutes.
• 6.3.5.4 / 7.4.5.4 The cumulative output capacity of the pump systems shall be sufficient to charge
the main accumulator system from precharge pressure to the system RWP within 15 minutes.
• 6.3.5.5 / 7.4.5.5 With the loss of one pump system or one power system, the remaining pump
systems shall have the capacity to charge the main accumulator system from precharge pressure to
the system RWP within 30 minutes.
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RP 53 vs. S53 – Pressure Testing (Subsea Systems)
The tables provide limited guidance on BOP testing requirements or
frequency. • 17.3.3 PRESSURETEST FREQUENCY
Pressure tests on the well control equipment should be conducted at least:
a. Prior to spud or upon installation.
b. After the disconnection or repair of any pressure containment
seal in the BOP stack, choke line, or choke manifold, but limited to the affected component.
c. Not to exceed 21 days.
Tables and sections specific to Emergency Systems also contain
additional requirements for testing the BSR and CSR. • 7.6.5.4 Pressure Test Frequency
7.6.5.4.1 Pressure tests on the well control equipment shall be conducted
a) predeployment of the BOP subsea and upon installation;
b) after the disconnection or repair of any pressure containment seal in the BOP stack, choke line,
kill line, choke manifold, or wellhead assembly but limited to the affected component;
c) in accordance with equipment owner’s PM program or site-specific requirements; and
d) not to exceed intervals of 21 days, excluding BSRs.
7.6.5.4.2 Blind shear rams shall be tested upon initial installation and at each subsequent casing point in
accordance with Table 10.
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RP 53 vs. S53 – Failure Reporting
17.13.3 MAINTENANCE HISTORY AND PROBLEM REPORTING
A maintenance and repair historical file should be maintained by serial number on each major
piece of equipment. This file should follow the equipment when it is transferred. Equipment
malfunctions or failures should be reported in writing to the equipment manufacturers stated in NI
Specification 16A.
6.5.10.5 Maintenance History and Problem Reporting (similar language in subsea sections)
6.5.10.5.1 A maintenance and repair historical file shall be retained by serial number or unique
identification number for each major piece of equipment.
6.5.10.5.2 The maintenance and repair historical file shall follow the equipment when it is
transferred.
6.5.10.5.3 Equipment malfunctions or failures shall be reported in writing to the equipment
manufacturer in accordance with Annex B.
6.5.10.5.4 The equipment owner shall maintain a log of BOP and control system failures. The log
shall provide a description and history of the item that failed along with the corrective action. The
failure log shall be limited to items used for wellbore pressure control and the equipment used to
function this equipment.
6.5.10.5.5 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.
6.5.10.5.6 Electronic and/or hard copies of all documentation shall also be retained at an offsite
location.
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RP 53 vs. S53
In summary:
• API Standard 53 provides the guidance for developing and
revising other industry standards.
API Specifications, 16A, C and D.
API Standard 64 and 16AR (under development)
S53 is assisting in the revisions of the IADC Deepwater Well
Control Equipment Guide.
• Every effort has been made to meet or exceed the
recommendations from the JITF.
• More robust language toward building certain levels of
consistency within the industry.
• Developed in assistance with an international community.
• Collaboration between industry and regulators continues to be a
good practice and should continue on into the future.
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