API 53 Changes - 4th Edition vs. 3rd Edition.pdf

Differences between RP 53 and Standard 53 (S53)

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25, August 2010

Assignment

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.

Certification

S53

RP53

A planned maintenance system, with equipment identified, tasks specified, and the time intervals between tasks stated, shall be employed on each rig.

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 Electronic and/or hard copy repairs made should be records for maintenance, repairs maintained on file at the rig site and remanufacturing performed or readily available for the for the well control equipment, applicable BOP equipment. shall be maintained on file at the rig site and preserved at an offsite Certification is mentioned 8 times location until the equipment is in RP53 and used in sections: permanently removed from the rig or service. 17.13.2 Electronic and/or hard copy 17.3.8 records of remanufactured parts and/or assemblies shall be readily 18.13.2 available and preserved at an 18.3.8 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 2

25, August 2010

Shear ram configuration / spacing

Assignment

S53

RP53

6.1.2.7 thru 6.1.2.13 address the requirements Given today’s shearing capability, industry for Blind and BSR's for surface BOP operations. agrees that two shear rams (SR), one of which can seal, are required in order to ensure that 7.1.3.1.6 c) A minimum of two sets of shear the stack will be able to shear the drill pipe in rams for shearing the drill pipe and tubing in the event a tool joint is across one of the SRs. use, of which at least one shall be capable of sealing. For moored rigs, a minimum of one set Since this configuration may reduce the of BSRs (capable of sealing) for shearing the redundancy available for more frequently drill pipe and tubing in use may be used after used stack functions (i.e., pipe rams), industry conducting a risk assessment in accordance N/A for surface. is developing alternate options. with 7.1.3.2. 7.3.2. d – Blind Shear For example, shear ram technology that is 7.1.3.2 identifies specific items that need to be rams are used in capable of shearing both tool joint and drill included in the Risk Assessment before removal place of blind rams. pipe with one ram is under consideration. If of the second shearing ram is removed from this technology becomes commercially the BOP Arrangement. available, industry proposes the option of returning to a single shear ram. This provides 7.3.8 Dedicated Accumulator Systems The additional pipe ram capability to close on the dedicated accumulators are supplied by the wide range of pipe sizes used in drilling and main accumulator system or a dedicated completion operations. pump/accumulator supply, but shall not be affected if the main supply is depleted or lost. Additional time is needed to determine if the dual SR requirement would improve safety on Sections 6.5.10.7 and 7.6.11.7 specifically moored rig operations. address the use of BSR's and CSR's.

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25, August 2010

Assignment

S53

RP53

Critical functions for ROV intervention identified

ROV Intervention

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 Industry agrees with the 7.3.20 Secondary Control System minimum requirement for 7.3.20.1 ROV Intervention ROV intervention capabilities. 7.3.20.2 Acoustic Control Systems (optional)

N/A

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 4

25, August 2010

Assignment

S53

RP53

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).

Arming / Disarming secondary controls

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.

Industry recommends that autoshear and deadman are armed at all times (after latch up) and MOC process is 7.4.14.3 The Autoshear system shall be armed while the BOP required to disarm. 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.

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.

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25, August 2010

Intervention ports

Assignment

Industry recommends standardization on API 17H high-flow single-port stabs.

S53

RP53

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

Intervention ports (continued)

Assignment

Industry recommends standardization on API 17H high-flow single-port stabs.

S53

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.

RP53

N/A

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25, August 2010

ROV performance standards

Assignment

S53

Using ROV intervention to test BOP critical functions subsea is currently achievable, but Along with the text within the document, the requirements are should not be limited to direct summarized in tables 6, 7, 8, 9 &10 for pre-deployment, initial ROV-powered function. and subsequent testing requirements for primary, secondary Testing may also be and emergency systems. Frequency of testing and acceptance accomplished through ROV criteria included. facilitation such as piloting, hot line, etc.

RP53

N/A

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25, August 2010

Assignment

Industry recognizes the need for ROV access to the BOP (i.e., ROV interface below rams). However, installing the interface below the lowest ram is lowest ram not advisable. Risks significantly outweigh benefits.

S53

RP53

N/A

N/A

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25, August 2010

Assignment

Industry recommends surface testing, (function and pressure) of all BOP and ROV intervention functions to verify the Surface / Subsea functionality of the system on surface. testing of ROV and Industry recommends subsea testing only the BOP stack capabilities 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.

S53

RP53

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

Subsea testing

Assignment

S53

Industry recommends the following testing requirements: Conduct a full surface function and pressure test prior to running the BOP stack to simulate Along with the text within the document, the (if equipped): requirements are summarized in tables 6, 7, 8, 1) unintended disconnect of LMRP 9 &10 for pre-deployment, initial and 2) loss of surface control of the subsea BOP subsequent testing requirements for primary, stack secondary and emergency systems. Frequency 3) Emergency disconnect sequence Industry of testing and acceptance criteria included. proposes continued study on the value of performing subsea testing of the emergency control systems.

RP53

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

Electronic log from BOP control system

Assignment

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.

S53

RP53

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.

Data acquisition is only required in 7.4 Electro-hydraulic and Multiplex Control terms of capturing Systems for Subsea BOP Stacks test data in the 7.4.10 Data Acquisition and Remote Monitoring testing sections of 7.4.10.1 Data shall be captured or logged subsea. during the course of well drilling operations. 7.4.10.2 Data captured shall include as a (17.3.7 and 18.3.7 of minimum the time and date stamp, solenoid RP53) 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).

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25, August 2010

Moored rigs and secondary controls

Assignment

S53

Industry recommends that moored vessels All that applies to DP rig operations apply to have at least a deadman emergency system moored rig operations with the excempt of the and one secondary control system (e.g., ROV). requirement to have an active EDS and the ability to be able to perform a risk assessment NOTE: Industry recommends that DP rigs have for the option of operating with only one BSR in one secondary control system and an EDS, a subsea stack. Otherwise, two shearing rams, autoshear, and deadman emergency system. at least one capable of sealing, is required.

RP53

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. •

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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. 18

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. 21

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.

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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. 27

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. • •

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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. 31

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) 32

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.

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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.

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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.

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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. 35

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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