API 53 Principais Mudanças - 4edição vs 3 Edição

2005 US-China Standards & Conformity Assessment Workshop

1

Differences between RP 53and Standard 53 (S53)

225, August 2010AssignmentS53RP53

CertificationAPI 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: 6.5.10.47.6.11.4A 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:

17.13.217.3.8

18.13.218.3.8


Shear ram configuration / spacingGiven todays 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 requirementsfor 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.


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 Stacks7.3.1.5 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/Sequence7.3.17.1 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 System7.3.19 Deadman System7.3.20 Secondary Control System7.3.20.1 ROV Intervention7.3.20.2 Acoustic Control Systems (optional)

7.4 Electro-hydraulic and Multiplex Control Systems for Subsea BOP Stacks7.4.1.5 The minimum required components of the BOP control system shall include the following: k) emergency systems; l) secondary control systems7.4.13 Emergency Disconnect System/Sequence7.4.14 Autoshear System7.4.15 Deadman System7.4.16 Secondary Control Systems7.4.16.1 ROV Intervention7.4.16.2 Acoustic Control System

N/A


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 owners 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 owners 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 owners 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 owners SOP.

Deadman Autoshear is optional.


Intervention ports

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

7.3 Discrete Hydraulic Control Systems for Subsea BOP Stacks7.3.20 Secondary Control System7.3.20.1 ROV Intervention7.3.20.1.1 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


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 Stacks7.4.16 Secondary Control Systems7.4.16.1 ROV Intervention7.4.16.1.1 The BOP stack shall be equipped with ROV intervention equipment that at a minimum allowsthe 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


ROVperformance 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


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


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.


N/A


Subsea testing

Industry recommends the following testingrequirements:Conduct a full surface function and pressure test prior to running the BOP stack to simulate (if equipped):1) unintended disconnect of LMRP2) loss of surface control of the subsea BOPstack3) Emergency disconnect sequence Industry proposes continued study on the value of performing subsea testing of the emergency control systems.


Tables 3 & 4 specific to pressure and function testing, predeployment, upon installation and subsequent. Nothing on requirements for testing secondary or emergency systems.


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 Stacks7.4.10 Data Acquisition and Remote Monitoring7.4.10.1 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)


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

14

Letslookatthedifferencesbetween RP53 and S53

RP-53Standard 53SectionSection

energy

1 Scope2 References1 Scope2 Normative References

3 Def initions a nd Abbreviations3Terms,Definitions and Abbreviations

4 Diverter Systems - Surface BOP lnstallatio ns4BOP Press ure Sealing Components

5 Diverter Systems - Subsea BOP lnstallatio ns5BIowout Preventers for Hydrogen Sulf ide Service

5Surface BOP Stack Arrangerr:ents5Surface BOP Systems

7Sub,.sea BOP Stack Arra ngements5.1Surface BOP Systems

gChoke Manifolds and Choke Unes - Surface BOP lnsta llations5.2 Surface BOP Stack Arrangements

Choke Manifolds Subsea BOP lnstallations5

.3 Choke Manifolds, Choke Unes and Kill Unes - Subsea BOP1nstaliations

10Kill Unes - for Surface BOP lnstallations5A Aux iliary Equipment11Kill Unes - for Subsea BOP lnstallations5.5 Maintenance and Testing - Surface BOP Systems

12Control Systems for Surface BOP Stac ks

7Subsea BOP Systems

13Control Systems for Subsea BOP Stacks

7.1Sub,sea BOP Stac k Arra ngements

Electro-Hydra ulic and Multiplex Control Systems for Subsea BOP14Stacks

7.2

Choke Manifolds,Choke Unes and Kill Unes - Subsea BOP lnsta llations

15Aux iliary Equipment - Surface BOP lnstallations7.3 Elect rn-Hydraulic and Multiplex Contr,ol Systems for Subs.ea BOP Stacks

15Aux iliary Equipment - Sub,sea BOP lnstallations7.4 Aux iliary Equipment for Subsea BOP Stacks

Test and Maintenance - Surface BOP Stac ks and Well Control17Equipment

7 .s Maintenance and Testing - Subs.ea BOP Systems

Test and Ma intena nce - Sub,sea BOP Stacks and Well Control Equipment

19 BOP Sealing Components

20 BIowout Preventers for Hydrogen Sulfide Service

21 Pipe Stripping Arra ngeme nts - Surfa,ce BOP lnstallatio ns

22 Pipe Str ipping Arra ngements - Subsea BOP lnstallatio ns

Appendix A - Forms

RP-53Standard 53

Annexes

Subsea Acc umulator Function Test WorksheetA

Forms ( informative)

Subsea Acc umulator Closing Test W orksheet

BFailure Reporting ( normative)

Surface A cc umulator Closing Test WorksheeteAcc umulator Prec harge Calculations ( informative) DAc oustic S stem Field Testin normative

Example Fi ures1

2K RWP Service - Surface lnstallations

Example Fi ures1

Choke Manifold for 2 K and 3 K RWP Service- Surface BOP1nstaliations

23 K and 5 K RWP Service - Surface lnstallations

3 lOK,15 K and 20K RWP Service - Surface lnstallations

4 2 K and 3 K RWP Service - Subsea lnstallations

5 5 K, OK and 15 K RWP Service - Subsea lnstallations

6 Choke Manifold Assembly for 2 K and 3 K for Surface BOP lnstallations7 Choke Ma nifold Assembly for 5 K for Surface BOP lnstallations Choke Manifold As.sembly for OK, 15K and 20K for Surface BOP8lnstallationsChoke Ma nifold Assembly for 5 K, OK a nd 15K - Sub.sea BOP9lnstallations10Kill Line Assembly for 2K and 3 K for Surface BOP lnstallations

11Kill Line Assembly for 5 K, OK and 15 K for Surface BOP lnstallations

12Kill Line Assembly for 5 K, OK and 15 K for Surface BOP lnstallations 13Riser Mounted Kill and Choke Lines for Subsea lnstallations14Subsea BOP Stac k lllustrating Option loc ations for Kill/Choke Unes1.5Flex ible Connector at the Top of Marine Riser for Kill/Choke Lines16Flex ible Connector at the Bottom of Marine Ris.er for Kill/Choke Lines17Hydraulic Control System for a BOP Control System18Standpipe Choke lnsta llation19 Iliustration of Ram BOP Sp.ace Out20 lllustration of Ram BOP Space Out21 Surface BOP Stac k/Choke Manifold lnstallation

2

3

4

5

6

7

8

9

10

11

12

13

14A.1A.2 A.3 AA

Choke Manifold for 5 K RWP Service- Surface BOP lnstallations Choke Manifold for OK or Greater RWP Service- Surface BOP lnstallationsKill Line As.sembly for 2 K a nd 3 K RWP Service - Surface BOPlnstallationsKill Line As.sembly for 5 K a nd Greater RWP Service - Surface BOP lnstallationsKill Line Assembly for 5 K a nd Greater RWP Service - Surface BOP lnstallationsSta ndpipe Choke lnstallation

lllustration of Surface Ram BOP Space-Out

Choke and Kill Manifold for Subsea Systems

Riser-mounted Kill and Choke Lines for Subs.ea BOP lnsta llations Subsea BOP Stac k lllustrating Optional Locations for Choke/K ill LinesFlex ible Connection at the Top of Marine Riser for Kill/Choke LinesFlex ible Connection at the Bottom of Marine Riser for Kill/ Choke Lineslllustration of Susbea Ram BOP Space-OutSurface BOP Function Test W orksheet Surface BOP Drawdown Test W orksheet Subsea BOP Function Test WorksheetSubsea BOP Field Drawdown Test Worksheet

RPS3Standard 53TablesTablesRecommended Pressure est Practices - Land and Bottom Supported

1Rigs (prior to spud or upon installationlRecommended Pressure est Practices - Land and Bottom Supported2Rigs (nottoexceed 21days)1 Surface BOP Pressure Designations

2 Pressure est,Surface BOPSys.tems,lnitial ests

Recommended Pressure est Practices,Floating Rigs with Sub5'ea BOP3Stac ks (divetrer system prior to spud,et a i,prior to running stac k)

3Pressure est,Surface BOPSystems,Suh5'equent ests

Recommended Pressure est Practices,Floating Rigs with Sub5'ea BOP4Stac ks [(a) BOP stac k initially installed on wellhead and (b) not to4ex ceed 21days].

Example Surface MEWSP Calculations Given Well and Equipment Speci ic Data

5Elastomer Compund Marking Code5Sub5'ea BOP Pressure Designation6Surface esting o Secondary,Emergency and other Systems7Sub5'ea Testing of Secondary,Emergency and other Systemsgother Systems estPressure est,Floating Rigs with Sub5'ea BOPStacks,Predeployment9Testing

10Pressure est,Floating Rigs with Sub5'ea BOPStacks,Subsea esting

Example Sub5'ea MEWSP Calculations Given Well and Equipment11Soecific Data

18RP 53 vs. S53 Changed document from Recommended Practice to Standard. Introduced the first upstream Standard, that was neither anRecommended Practice or Specification. Shall vs. ShouldRP53 = 50 vs. 635Standard 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, proceduresand operations.

19

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.

S53

20

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.

21

Clarification of the drawdown testing requirements and differences between Specification 16D and this Standard. (New language)

NOTE 1When 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 2Because 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.

S53(Surface and Subsea)

22

Incorporated the affects of negative pressure on BOPE, insubsea applications. Identified performance based maintenance as an alternative to scheduled based maintenance. For subsea operations, two BOPs 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).

S53

23

TERMS, DEFINITIONS AND ABBREVIATIONS

Clearly defined what a BOP is and isnt (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 tubulars, or in an open hole during well drilling, completion and testing operations.Note: A Blowout Preventer is not: a gate valve(s), workover controlpackage, Subsea Shutin Device (SSID or SID), Well ControlComponents (per API RP16ST), Intervention Control Packages,Diverters, Rotating Heads or Rotating Circulating Devices,Capping Stack, Snubbing or Stripping packages.

24


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 applicabilityto 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)

25


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.

26

Expanded tables for testing requirements, acceptance criteriaand 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.

27

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, 25Kand 30K systems

Defined BOP Classifications based on the quantity of rams and annulars for well control and emergency rams installed.

2817.10.3 MAJOR INSPECTIONSAfter every 3-5 years of service, the BOP stack, choke manifold, and diverter components should be disassembled and inspected in accordance with the manufacturers guidelines.

Elastomeric components should be changed out and surface finishes should be examined for wear and corrosion. Critical dimensions should be checked against the manufacturers 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 manufacturers 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 manufacturers guidelines. Individual components (e.g. ram bonnets, valve actuators) can be inspected on a staggered schedule.

RP 53 vs. S53Language for surface (Sections17.10.3 vs. 6.5.7.3)

296.5.7.3 Periodic Maintenance and Inspection (contd)

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 shearblades, 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 manufacturers 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.

30RP 53 vs. S53Language for surface (Sections 17.11.1 vs.6.5.8.1)

17.1 1.1 INSTALLATION, OPERATION, AND MAINTENANCE MANUALSManufacturers 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 .1 Installation, Operation, and Maintenance ManualsRig-specific procedures shall be developed for the installation, operation, and maintenance (IOM) of BOPs for the specific well and environmental conditions. The IOM manuals shall be available on the rig for all BOP equipment installed on the rig.

31RP 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 discussionS53 Sections 7.3.8, 7.3.18, 7.3.19,7.3.20 and Tables 6 & 7.

32RP 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 intoaccount 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)

33RP 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.

34RP 53 vs. S53 Pressure Testing (Subsea Systems) The tables provide limited guidance on BOP testing requirements or frequency. 17.3.3 PRESSURETEST FREQUENCYPressure 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 containmentseal 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 Frequency7.6.5.4.1 Pressure tests on the well control equipment shall be conducteda) 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 owners PM program or site-specific requirements; andd) 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.

35RP 53 vs. S53 Failure Reporting17.13.3 MAINTENANCE HISTORY AND PROBLEM REPORTINGA 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 maintainedfrom 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.

36RP 53 vs. S53In summary: API Standard 53 provides the guidance for developing andrevising 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 ofconsistency 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.

API 53 Principais Mudanças - 4edição vs 3 Edição

Documents

Transcript of API 53 Principais Mudanças - 4edição vs 3 Edição