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API Standards

Asset ID Document Title Description Preview Link Release Date
API STD 6AR 2ND ED (2019) Repair and Remanufacture of Wellhead and Tree Equipment; Second Edition 1 Scope

This standard identifies the requirements for repair and remanufacture of wellhead and tree equipment manufactured in conformance with API Specification 6A for continued service when specified by the user/ purchaser of the equipment.

This standard applies to equipment manufactured to editions of API 6A in which a product specification level (PSL) identifies the quality, material, and testing requirements for a specific product. Equipment identified as manufactured in conformance with API 6A prior to April 1986 (API 6A, 15th Edition) is outside the scope of this document.

This standard is not applicable to onsite repair at the equipment installation site.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/28322845-6f5c-4916-8321-265293babdbb.htm 01-Sep-19
ANSI/API BUL 100-3 1ST ED (2014) Community Engagement Guidelines; First Edition, July 2014 1.1 General

These guidelines outline what local communities and other key stakeholders can expect from operators. Oil and gas operators acknowledge the challenges associated with industry activities, which can include challenges important to a community. Principles of integrity, transparency and consideration for community concerns underpin responsible operations. Conscientious operators are committed to helping communities achieve positive and long-lasting benefits.

Both local stakeholders and operators can use this guidance. It is designed to acknowledge challenges and impacts that occur during the industry’s presence in a given region. It provides flexible and adaptable strategies, recognizing that application will vary from operator to operator and community to community. Many operators already apply similar guidelines or processes within their operations. These suggested guidelines are typical and reasonable and generally apply under normal operating circumstances. The use of these guidelines is at each individual operator’s discretion.

Operators recognize that stakeholders within the community can have different interests, issues and levels of concern. Some of these interests can be in direct conflict with one another. Working together with stakeholders to seek mutually agreeable solutions is an important aspect of community engagement. Operators can have different approaches to addressing the concerns and issues.

These guidelines are intended primarily to support onshore oil and gas projects in the United States for shale developments; however, they can be adapted to any oil and gas projects in the United States.

1.2 Conditions of Applicability

This document provides non-technical guidance only, and practices included herein cannot be applicable in all regions and/or circumstances. This document does not constitute legal advice regarding compliance with legal or contractual requirements or risk mitigation. It is not intended to be all-inclusive. The operator is responsible for determining compliance with applicable legal and regulatory requirements.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/08980f40-f946-4322-a98f-37976a9cd841.htm 01-Jul-14
ANSI/API RP 100-1 1ST ED (2015) Hydraulic Fracturing—Well Integrity and Fracture Containment; First Edition 1.1 This document contains recommended practices for onshore well construction and fracture stimulation design and execution as it relates to well integrity and fracture containment. The provisions in this document relate to the following two areas.

a) Well integrity: the design and installation of well equipment to a standard that

— protects and isolates useable quality groundwater,

— delivers and executes a hydraulic fracture treatment, and

— contains and isolates the produced fluids.

b) Fracture containment: the design and execution of hydraulic fracturing treatments to contain the resulting fracture within a prescribed geologic interval. Fracture containment combines those parameters that are existing, those that can be established at installation, and those that can be controlled during execution:

— existing— formation parameters with associated range of uncertainties;

— established— well barriers and integrity as created during well construction;

— controllable— fracture design and execution parameters.

1.2 The guidance from this document covers recommendations for pressure containment barrier design and well construction practices for onshore wells that will undergo hydraulic fracture stimulation. This document is specifically for wells drilled and completed onshore, although many of the provisions are applicable to wells in coastal waters.

1.3 This document does not attempt to address the full well life cycle of well operations although a brief paragraph on fracture stimulation for re-entries is included in 5.10. This document is not a detailed well construction or fracture design manual. This document does not apply to continuous injection operations such as water disposal, water-flooding or cuttings re-injection wells, or any other continuous injection operation.

1.4 API 100-2 is a companion document that also contains recommended practices applicable to the planning and operation of hydraulically fractured wells. This document includes recommendations for managing environmental aspects during well planning, construction, and execution.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/df4c7037-ebe5-49b2-a13d-6c8e665ab6a1.htm 01-Oct-15
ANSI/API RP 100-2 1ST ED (2015) Managing Environmental Aspects Associated with Exploration and Production Operations Including Hydraulic Fracturing; First Edition 1.1 General This document provides recommended practices applicable to the planning and operation of wells, and hydraulically fractured wells. Topics covered include recommendations for managing environmental aspects during planning; site selection; logistics; mobilization, rig-up, and demobilization; and stimulation operations. Also, this document includes guidance for managing environmental aspects during well construction. This document provides recommendations for the following topics:

a) baseline groundwater sampling;

b) source water management;

c) material selection;

d) transportation of materials and equipment;

e) storage and management of fluids and chemicals;

f) management of solid and liquid wastes;

g) air emissions;

h) site planning;

i) training;

j) noise and visual resources.

This document provides a general discussion of exploration and production operations, which does not supersede the review of applicable local, state, and federal regulatory requirements. Operators should consider available industry standards and guidance that can provide additional information. In addition to this document, API 100-1 contains recommended practices for well construction and fracture stimulation design and execution as it relates to well integrity, groundwater protection and fracture containment for onshore wells. The recommended practices relate to two areas: well integrity during the design and installation of well equipment, and fracture containment during the design and execution of hydraulic fracturing treatments.

1.2 Conditions of Applicability This document provides technical guidance only, and practices included herein may not be applicable in all regions and/or circumstances. This document does not constitute legal advice regarding compliance with legal or regulatory contractual requirements, risk mitigation, or internal company policies and procedures, where applicable. Where legal or regulatory requirements are mentioned, this document is not intended to be all-inclusive. The operator is responsible for determining compliance with applicable legal or regulatory requirements.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/967812dd-3643-4072-9e53-0e02a96b344e.htm 01-Aug-15
ANSI/API RP 10B-2 1ST ED (E1) Recommended Practice for Testing Well Cements; First Edition This part of ISO 10426 specifies requirements and gives recommendations for the testing of cement slurries and related materials under simulated well conditions.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/6ffe9dac-7fb1-46de-b095-a0dcfa1897d2.htm 01-Jul-05
ANSI/API RP 10B-3 1ST ED (2004) Recommended Practice on Testing of Deepwater Well Cement Formulations; First Edition; ISO 10426-3:2003 This part of ISO 10426 provides procedures for testing well cements and cement blends for use in the petroleum and natural gas industries in a deepwater environment.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/6080f59f-9648-444f-9a5d-58f9fbc68050.htm 01-Jul-04
ANSI/API RP 10B-3 1ST ED (R 2015) Recommended Practice on Testing of Deepwater Well Cement Formulations; First Edition; Reaffirmed, April 2015; ISO 10426-3:2003 This part of ISO 10426 provides procedures for testing well cements and cement blends for use in the petroleum and natural gas industries in a deepwater environment.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/42ebd281-0572-4d23-8d87-93dd72aa6536.htm 01-Jul-04
ANSI/API RP 10B-4 1ST ED (2004) Recommended Practice on Preparation and Testing of Foamed Cement Slurries at Atmospheric Pressure; First Edition; ISO 10426-4:2003 This part of ISO 10426 defines the methods for the generation and testing of foamed cement slurries and their corresponding unfoamed base cement slurries at atmospheric pressure.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/63aaa981-659b-4646-a5d8-735813950097.htm 01-Jul-04
ANSI/API RP 10B-4 1ST ED (R 2015) Recommended Practice on Preparation and Testing of Foamed Cement Slurries at Atmospheric Pressure; First Edition; ISO 10426-4:2003 This part of ISO 10426 defines the methods for the generation and testing of foamed cement slurries and their corresponding unfoamed base cement slurries at atmospheric pressure.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/30a60cca-efee-418c-ad9d-f71f04e2dd39.htm 01-Jul-04
ANSI/API RP 10B-5 1ST ED (2005) Recommended Practice on Determination of Shrinkage and Expansion of Well Cement Formulations at Atmospheric Pressure; First Edition This part of ISO 10426 provides the methods for the testing of well cement formulations to determine the dimension changes during the curing process (cement hydration) at atmospheric pressure only. This is a base document, because under real well cementing conditions shrinkage and expansion take place under pressure and different boundary conditions.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/3173ab50-6122-453b-bb1d-80d21bb1d028.htm 01-Apr-05
ANSI/API RP 10B-5 1ST ED (R 2015) Recommended Practice on Determination of Shrinkage and Expansion of Well Cement Formulations at Atmospheric Pressure; First Edition; Reaffirmed, April 2015; ISO 10426-5:2004 This part of ISO 10426 provides the methods for the testing of well cement formulations to determine the dimension changes during the curing process (cement hydration) at atmospheric pressure only. This is a base document, because under real well cementing conditions shrinkage and expansion take place under pressure and different boundary conditions.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/60d7d94b-67c5-4df1-b46a-d421dc4cbce8.htm 01-Apr-15
ANSI/API RP 10D-2 1ST ED (R 2015) Recommended Practice for Centralizer

Placement and Stop-collar Testing; First Edition

This part of ISO 10427 provides calculations for determining centralizer spacing, based on centralizer performance and desired standoff, in deviated and dogleg holes in wells for the petroleum and natural gas industries. It also provides a procedure for testing stop collars and reporting test results.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/f6233017-e69e-49d1-87e0-f4b4bfa81701.htm 01-Aug-04
ANSI/API RP 10D-2 1ST ED (R 2020) Recommended Practice for Centralizer Placement and Stop-collar Testing; First Edition This part of ISO 10427 provides calculations for determining centralizer spacing, based on centralizer performance and desired standoff, in deviated and dogleg holes in wells for the petroleum and natural gas industries. It also provides a procedure for testing stop collars and reporting test results.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/7ad6705a-954e-476c-b520-47cbbdce9f06.htm 01-Aug-04
ANSI/API RP 13B-1 3RD ED (E1) Recommended Practice for Field Testing Water-Based Drilling Fluids; Third Edition This part of ISO 10414 provides standard procedures for the determining following characteristics of water-based drilling fluids: a) drilling fluid density (mud weight); b) viscosity and gel strength; c) filtration; d) water, oil and solids contents; e) sand content; f) methylene blue capacity; g) pH; h) alkalinity and lime content; i) chloride content; j) total hardness as calcium. Annexes A, B, C and E provide additional test methods which may be used for k) chemical analysis for calcium, magnesium, calcium sulfate, sulfide, carbonate, potassium; l) determination of shear strength; m) determination of resistivity; n) drill pipe corrosion monitoring. Annexes D, F, G and H provide procedures that may be used for o) removal of air; p) sampling, inspection and rejection; q) rig-site sampling; r) calibration and verification of glassware, thermometers, viscometers, retort kit cup and drilling fluid balances.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/64474f48-dc3c-4b15-a32e-7d22b2ace563.htm 01-Dec-03
ANSI/API RP 13B-1 4TH ED (2009) Recommended Practice for Field Testing Water-Based Drilling Fluids; Fourth Edition This part of ISO 10414 provides standard procedures for determining the following characteristics of water-based drilling fluids:

a) drilling fluid density (mud weight);

b) viscosity and gel strength;

c) filtration;

d) water, oil and solids contents;

e) sand content;

f) methylene blue capacity;

g) pH;

h) alkalinity and lime content;

i) chloride content;

j) total hardness as calcium.

Annexes A through K provide additional test methods which may be used for

— chemical analysis for calcium, magnesium, calcium sulfate, sulfide, carbonate and potassium;

— determination of shear strength;

— determination of resistivity;

— removal of air;

— drill-pipe corrosion monitoring;

— sampling, inspection and rejection;

— rig-site sampling;

— calibration and verification of glassware, thermometers, viscometers, retort-kit cup and drilling-fluid balances;

— permeability-plugging testing at high temperature and high pressure for two types of equipment;

— example of a report form for water-based drilling fluid.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/374ef66b-c4f1-483b-a6dd-262cc6760087.htm 01-Mar-09
ANSI/API RP 13B-1 4TH ED (E1) Recommended Practice for Field Testing Water-Based Drilling Fluids; Fourth Edition This part of ISO 10414 provides standard procedures for determining the following characteristics of water-based drilling fluids:

a) drilling fluid density (mud weight);

b) viscosity and gel strength;

c) filtration;

d) water, oil and solids contents;

e) sand content;

f) methylene blue capacity;

g) pH;

h) alkalinity and lime content;

i) chloride content;

j) total hardness as calcium.

Annexes A through K provide additional test methods which may be used for

— chemical analysis for calcium, magnesium, calcium sulfate, sulfide, carbonate and potassium;

— determination of shear strength;

— determination of resistivity;

— removal of air;

— drill-pipe corrosion monitoring;

— sampling, inspection and rejection;

— rig-site sampling;

— calibration and verification of glassware, thermometers, viscometers, retort-kit cup and drilling-fluid balances;

— permeability-plugging testing at high temperature and high pressure for two types of equipment;

— example of a report form for water-based drilling fluid.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/d700249c-837d-46c5-87a7-3ebca934e605.htm 01-Mar-09
ANSI/API RP 13B-1 4TH ED (E1) (R 2016) Recommended Practice for Field Testing Water-Based Drilling Fluids; Fourth Edition; Reaffirmed March 2016; ISO 10414-1:2008 This part of ISO 10414 provides standard procedures for determining the following characteristics of water-based drilling fluids: a) drilling fluid density (mud weight); b) viscosity and gel strength; c) filtration; d) water, oil and solids contents; e) sand content; f) methylene blue capacity; g) pH; h) alkalinity and lime content; i) chloride content; j) total hardness as calcium. Annexes A through K provide additional test methods which may be used for — chemical analysis for calcium, magnesium, calcium sulfate, sulfide, carbonate and potassium; — determination of shear strength; — determination of resistivity; — removal of air; — drill-pipe corrosion monitoring; — sampling, inspection and rejection; — rig-site sampling; — calibration and verification of glassware, thermometers, viscometers, retort-kit cup and drilling-fluid balances; — permeability-plugging testing at high temperature and high pressure for two types of equipment; — example of a report form for water-based drilling fluid.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/055cf369-09ae-4253-a234-c1f60b62b1c2.htm 01-Mar-16
ANSI/API RP 13C 4TH ED (2010) Recommended Practice on Drilling Fluids Processing Systems Evaluation; Fourth Edition This International Standard provides a standard procedure for assessing and modifying performance of solids control equipment systems commonly used in the field in petroleum and natural gas drilling fluids processing.

This procedure is not intended for the comparison of similar types of individual pieces of equipment.

Clause 11 in this document replaces Clause 11 currently in the ISO 13501:2005. It specifies a different labelling requirement for shale shaker screens that will be permanently attached to the screen. It also covers the marking of shipping containers for shale shaker screens.

This International Standard Annex B provides a standard procedure for quick assessment of a solids control screen sizing. The method can be used in the field or laboratory for identification of an unknown screen approximate size range. It is provided for information only and does not replace or supplement the normative testing shown in Clauses 9 through Clause 11 in this document.

This procedure is not intended for the operating comparison or ranking of similar types of individual pieces of equipment.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/1c2cbb73-8667-4a7a-83a0-d00d219db95c.htm 01-Dec-10
ANSI/API RP 13I 8TH ED (2009) Recommended Practice for Laboratory Testing of Drilling Fluids; Eighth Edition; ISO 10416:2008 This International Standard provides procedures for the laboratory testing of both drilling fluid materials and drilling fluid physical, chemical and performance properties. It is applicable to both water-based and oil-based drilling fluids, as well as the base or “make-up” fluid.

It is not applicable as a detailed manual on drilling fluid control procedures. Recommendations regarding agitation and testing temperature are presented because the agitation history and temperature have a profound effect on drilling fluid properties.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/784b1f11-da7b-46eb-b6ec-a862af7efd1f.htm 01-Mar-09
ANSI/API RP 13I 8TH ED (R 2016) Recommended Practice for Laboratory Testing of Drilling Fluids; Eighth Edition; ISO 10416:2008; Reaffirmed, March 2016 This International Standard provides procedures for the laboratory testing of both drilling fluid materials and drilling fluid physical, chemical and performance properties. It is applicable to both water-based and oil-based drilling fluids, as well as the base or “make-up” fluid.

It is not applicable as a detailed manual on drilling fluid control procedures. Recommendations regarding agitation and testing temperature are presented because the agitation history and temperature have a profound effect on drilling fluid properties.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/49232145-8757-41cb-a04e-8c2aaea12e6f.htm 01-Mar-09
ANSI/API RP 13J 4TH ED (2006) Testing of Heavy Brines; Fourth Edition; ISO 13503-3:2005 This part of ISO 13503 covers the physical properties, potential contaminants and test procedures for heavy brine fluids manufactured for use in oil and gas well drilling, completion and workover fluids.

This part of ISO 13503 provides methods for assessing the performance and physical characteristics of heavy brines for use in field operations. It includes procedures for evaluating the density or specific gravity, the clarity or amount of particulate matter carried in the brine, the crystallization point or the temperature (both ambient and under pressure) at which the brines make the transition between liquid and solid, the pH, and iron contamination.

It also contains a discussion of gas hydrate formation and mitigation, brine viscosity, corrosion testing, buffering capacity and a standardised reporting form.

This part of ISO 13503 is intended for the use of manufacturers, service companies and end-users of heavy brines.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/29f5603d-a597-4607-bd4b-92d82763cade.htm 01-May-06
ANSI/API RP 13M 1ST ED (2004) Recommended Practice for the Measurement of Viscous Properties of Completion Fluids; First Edition This part of ISO 13503 provides consistent methodology for determining the viscosity of completion fluids used in the petroleum and natural gas industries. For certain cases, methods are also provided to determine the rheological properties of a fluid.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/74d03b23-f5d6-49fc-8641-9afc0d3c5df3.htm 01-Jul-04
ANSI/API RP 13M 1ST ED (R 2010) Recommended Practice for the Measurement of Viscous Properties of Completion Fluids; First Edition; Reaffirmed, October 2010; ISO 13503-1:2003 This part of ISO 13503 provides consistent methodology for determining the viscosity of completion fluids used in the petroleum and natural gas industries. For certain cases, methods are also provided to determine the rheological properties of a fluid.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/54298d5b-9680-4bb0-bd59-226d5577e77c.htm 01-Jul-04
ANSI/API RP 13M 1ST ED (R 2018) Recommended Practice for the Measurement of Viscous Properties of Completion Fluids; First Edition; Reaffirmed, December 2018; ISO 13503-1:2003 This part of ISO 13503 provides consistent methodology for determining the viscosity of completion fluids used in the petroleum and natural gas industries. For certain cases, methods are also provided to determine the rheological properties of a fluid.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8aeb1f32-9286-48f3-9a2e-8bef344ba70f.htm 01-Jul-04
ANSI/API RP 13M-4 1ST ED (2006) Recommended Practice for Measuring Stimulation and Gravel-Pack Fluid Leakoff Under Static Conditions; First Edition This part of ISO 13503 provides for consistent methodology to measure fluid loss of stimulation and gravel-pack fluid under static conditions. However, the procedure in this part of ISO 13503 excludes fluids that react with porous media.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/784160e9-4c78-4ee9-8145-ce4fa08469be.htm 01-Dec-06
ANSI/API RP 13M-4 1ST ED (R 2015) Recommended Practice for Measuring Stimulation and Gravel-pack Fluid Leakoff Under Static Conditions; First Edition; Reaffirmed, July 2015; ISO 13503-4:2006 This part of ISO 13503 provides for consistent methodology to measure fluid loss of stimulation and gravel-pack fluid under static conditions. However, the procedure in this part of ISO 13503 excludes fluids that react with porous media.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5c0e398d-d138-407a-8129-76469ec9a278.htm 01-Jul-15
ANSI/API RP 14B 5TH ED (2005) Design, Installation, Repair and Operation of Subsurface Safety Valve Systems; Fifth Edition; ISO 10417:2004 This International Standard establishes requirements and provides guidelines for configuration, installation, test, operation and documentation of subsurface safety valve (SSSV) systems. In addition, this International Standard establishes requirements and provides guidelines for selection, handling, redress and documentation of SSSV downhole production equipment.

This International Standard is not applicable to repair activities.

NOTE ISO 10432 provides requirements for SSSV equipment repair.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/036298ae-7106-4337-a039-c28fea2cae04.htm 01-Oct-05
ANSI/API RP 14B 5TH ED (R 2012) Design, Installation, Repair and Operation of Subsurface Safety Valve Systems; Fifth Edition; Reaffirmed, July 2012; ISO 10417:2004 This International Standard establishes requirements and provides guidelines for configuration, installation, test, operation and documentation of subsurface safety valve (SSSV) systems. In addition, this International Standard establishes requirements and provides guidelines for selection, handling, redress and documentation of SSSV downhole production equipment.

This International Standard is not applicable to repair activities.

NOTE ISO 10432 provides requirements for SSSV equipment repair.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c0c64631-11bb-4664-bdb0-063f6de6740c.htm 01-Oct-05
ANSI/API RP 17A 4TH ED (2006) Recommended Practice for Design and Operation of Subsea Production Systems; Fourth Edition; ISO 13628-1:2005 This part of ISO 13628 provides general requirements and overall recommendations for development of complete subsea production systems from the design phase to decommissioning. This part of ISO 13628 forms a top-level document to govern other standards dealing with subsystems typically forming a part of a subsea production system.

The complete subsea production system comprises several subsystems necessary to produce hydrocarbons from one or more subsea wells to a given processing facility located offshore (fixed, floating or subsea) or onshore, or to inject water/gas through subsea wells. This part of ISO 13628 and the subsystem standards apply as far as the interface limits described in clause 4.

Specialized equipment, such as split trees and trees and manifolds in atmospheric chambers, are not specifically discussed because of their limited use. However, the information presented is applicable to those types of equipment.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/77d3f30e-0e0e-4e61-b5c1-6de992d3c629.htm 01-Sep-06
ANSI/API RP 17A 4TH ED (R 2011) Design and Operation of Subsea Production Systems—General Requirements and Recommendations; Fourth Edition; Reaffirmed, April 2011; ISO 13628-1:2005 This part of ISO 13628 provides general requirements and overall

recommendations for development of complete subsea production systems, from the design phase to decommissioning and abandonment. This part of ISO 13628 is intended as an umbrella document to govern other parts of ISO 13628 dealing with more detailed requirements for the subsystems which typically form part of a subsea production system. However, in some areas (e.g. system design, structures, manifolds, lifting devices, and colour and marking) more detailed requirements are included herein, as these subjects are not covered in a subsystem standard.

The complete subsea production system comprises several subsystems necessary to produce hydrocarbons from one or more subsea wells and transfer them to a given processing facility located offshore (fixed, floating or subsea) or onshore, or to inject water/gas through subsea wells. This part of ISO 13628 and its related subsystem standards apply as far as the interface limits described in Clause 4.

Specialized equipment, such as split trees and trees and manifolds in atmospheric chambers, are not specifically discussed because of their limited use. However, the information presented is applicable to those types of equipment.

If requirements as stated in this part of ISO 13628 are in conflict with, or are inconsistent with, requirements as stated in the relevant complementary parts of ISO 13628, then the specific requirements in the complementary parts take precedence.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/fe88099d-e8ea-4fa2-9a28-58d752b40f1f.htm 01-Jan-06
ANSI/API RP 17B 4TH ED (E1) Recommended Practice for Flexible Pipe; Fourth Edition; ISO 13628-11:2007 This part of ISO 13628 provides guidelines for the design, analysis, manufacture, testing, installation and operation of flexible pipes and flexible pipe systems for onshore, subsea and marine applications. This part of ISO 13628 supplements ISO 13628-2 and ISO 13628-10, which specify minimum requirements for the design, material selection, manufacture, testing, marking and packaging of unbonded and bonded flexible pipe, respectively.

This part of ISO 13628 applies to flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. Both bonded and unbonded pipe types are covered. In addition, this part of ISO 13628 applies to flexible pipe systems, including ancillary components.

The applications covered by this part of ISO 13628 are sweet- and sour-service production, including export and injection applications. This part of ISO 13628 applies to both static and dynamic flexible pipe systems used as flowlines, risers and jumpers. This part of ISO 13628 does cover, in general terms, the use of flexible pipes for offshore loading systems.

NOTE Refer also to Reference [30] for offshore loading systems.

This part of ISO 13628 does not cover flexible pipes for use in choke and kill lines or umbilical and control lines.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/220c4ce2-5ff5-48f5-8712-44a5d1d192d5.htm 01-Jul-08
ANSI/API RP 17C 2ND ED (R 2010) Recommended Practice on TFL (Through Flowline) Systems; Second Edition; Reaffirmed, February 2010; ISO 13628-3:2000 This part of ISO 13628 specifies requirements and gives recommendations for

the design, fabrication and operation of TFL equipment and systems.

The procedures and requirements presented are for the hydraulic servicing of downhole equipment, subsea tree and tubing hanger, and flowlines and equipment within the flowlines.

This part of ISO 13628 primarily addresses TFL systems for offshore, subsea applications but it may also be used in other applications such as highly-deviated wells or horizontally-drilled wells.

Subsea separation, boosting, metering and downhole pumps are outside the scope of this part of ISO 13628.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/44011c2f-1f82-4ae5-8b26-8508c7390e7b.htm 01-Sep-02
ANSI/API RP 17G 2ND ED (R 2011) Recommended Practice for Completion/Workover Risers; Second Edition; Reaffirmed, April 2011 This part of ISO 13628 gives requirements and recommendations for the design,

analysis, materials, fabrication, testing and operation of subsea completion/workover (C/WO) riser systems run from a floating vessel.

It is applicable to all new C/WO riser systems and may be applied to modifications, operation of existing systems and reuse at different locations and with different floating vessels.

This part of ISO 13628 is intended to serve as a common reference for designers, manufacturers and operators/users, thereby reducing the need for company specifications.

This part of ISO 13628 is limited to risers, manufactured from low alloy carbon steels. Risers fabricated from special materials such as titanium, composite materials and flexible pipes are beyond the scope of this part of ISO 13628.

Specific equipment covered by this part of ISO 13628 is listed as follows:

— riser joints;

— connectors;

— workover control systems;

— surface flow trees;

— surface tree tension frames;

— lower workover riser packages;

— lubricator valves;

— retainer valves;

— subsea test trees;

— shear subs;

— tubing hanger orientation systems;

— swivels;

— annulus circulation hoses;

— riser spiders;

— umbilical clamps;

— handling and test tools;

— tree cap running tools.

Associated equipment not covered by this part of ISO 13628 is listed below:

— tubing hangers;

— internal and external tree caps;

— tubing hanger running tools;

— surface coiled tubing units;

— surface wireline units;

— surface tree kill and production jumpers.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/929c9b72-7e29-4f4e-8527-4048ab28cbfb.htm 01-Jul-06
ANSI/API RP 17G 2ND ED (R 2016) Recommended Practice for Completion/Workover Risers; Second Edition; Reaffirmed, September 2016; ISO 13628-7:2005 This part of ISO 13628 gives requirements and recommendations for the design,

analysis, materials, fabrication, testing and operation of subsea completion/workover (C/WO) riser systems run from a floating vessel.

It is applicable to all new C/WO riser systems and may be applied to modifications, operation of existing systems and reuse at different locations and with different floating vessels.

This part of ISO 13628 is intended to serve as a common reference for designers, manufacturers and operators/users, thereby reducing the need for company specifications.

This part of ISO 13628 is limited to risers, manufactured from low alloy carbon steels. Risers fabricated from special materials such as titanium, composite materials and flexible pipes are beyond the scope of this part of ISO 13628.

Specific equipment covered by this part of ISO 13628 is listed as follows:

— riser joints;

— connectors;

— workover control systems;

— surface flow trees;

— surface tree tension frames;

— lower workover riser packages;

— lubricator valves;

— retainer valves;

— subsea test trees;

— shear subs;

— tubing hanger orientation systems;

— swivels;

— annulus circulation hoses;

— riser spiders;

— umbilical clamps;

— handling and test tools;

— tree cap running tools.

Associated equipment not covered by this part of ISO 13628 is listed below:

— tubing hangers;

— internal and external tree caps;

— tubing hanger running tools;

— surface coiled tubing units;

— surface wireline units;

— surface tree kill and production jumpers.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d89dd72f-61c5-4bca-ba56-189cbd6de92a.htm 01-Jul-06
ANSI/API RP 17H 1ST ED (R 2009) Remotely Operated Vehicle (ROV) Interfaces on Subsea Production Systems; First Edition; Reaffirmed, January 2009 This part of ISO 13628 gives functional requirements and guidelines for ROV interfaces on subsea production systems for the petroleum and natural gas industries. It is applicable to both the selection and use of ROV interfaces on subsea production equipment, and provides guidance on design as well as the operational requirements for maximising the potential of standard equipment and design principles. The auditable information for subsea systems it offers will allow interfacing and actuation by ROV-operated systems, while the issues it identifies are those that have to be considered when designing interfaces on subsea production systems. The framework and detailed specifications set out will enable the user to select the correct interface for a specific application.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/8bc26fb6-3d38-4875-aaf4-23d2f20e67a5.htm 01-Jul-04
ANSI/API RP 17M 1ST ED (R 2009) Recommended Practice on Remotely Operated Tool (ROT) Intervention Systems; First Edition; Reaffirmed, January 2009 This part of ISO 13628 provides functional requirements and recommendations for ROT intervention systems and interfacing equipment on subsea production systems for the petroleum and natural gas industries.

This part of ISO 13628 does not cover manned intervention and ROV-based intervention systems (e.g. for tie-in of sealines and module replacement). Vertical wellbore intervention, internal flowline inspection, tree running and tree running equipment are also excluded from this part of ISO 13628.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/1b0a2412-a3a1-4834-83c3-aa3d03b2848d.htm 01-Apr-04
ANSI/API RP 17P 1ST ED (2013) Design and Operation of Subsea Production Systems—Subsea Structures and Manifolds; First Edition This part of ISO 13628 addresses recommendations for subsea structures and manifolds, within the frameworks set forth by recognized and accepted industry specifications and standards. As such, it does not supersede or eliminate any requirement imposed by any other industry specification.

This part of ISO 13628 covers subsea manifolds and templates utilized for pressure control in both subsea production of oil and gas, and subsea injection services. See Figure 1 for an example of such a subsea system.

Equipment within the scope of this part of ISO 13628 is listed below:

a) the following structural components and piping systems of subsea production systems:

— production and injection manifolds,

— modular and integrated single satellite and multiwell templates,

— subsea processing and subsea boosting stations,

— flowline riser bases and export riser bases (FRB, ERB),

— pipeline end manifolds (PLEM),

— pipeline end terminations (PLET),

— T- and Y-connection,

— subsea isolation valve (SSIV);

b) the following structural components of subsea production system:

— subsea controls and distribution structures,

— other subsea structures;

c) protection structures associated with the above.

The following components and their applications are outside the scope of this part of ISO 13628:

— pipeline and manifold valves;

— flowline and tie-in connectors;

— choke valves;

— production control systems.

NOTE General information regarding these topics can be found in additional publications, such as ISO 13628-1 and API Spec 2C.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0f1c06c6-14e4-4fd1-8c2f-7d03bf65b45a.htm 01-Jan-13
ANSI/API RP 19C 1ST ED (2008) Measurement of Properties of Proppants Used in Hydraulic Fracturing and Gravel-Packing Operations; First Edition; ISO 13503-2:2006 This part of ISO 13503 provides standard testing procedures for evaluating proppants used in hydraulic fracturing and gravel-packing operations.

NOTE “Proppants” mentioned henceforth in this part of ISO 13503 refer to sand, ceramic media, resin-coated proppants, gravel-packing media and other materials used for hydraulic fracturing and gravel-packing operations.

The objective of this part of ISO 13503 is to provide a consistent methodology for testing performed on hydraulic fracturing and/or gravel-packing proppants.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/15aba382-e01f-412b-8a4e-7d6b9d3b7655.htm 01-May-08
ANSI/API RP 19C 1ST ED (R 2016) Measurement of Properties of Proppants Used in Hydraulic Fracturing and Gravel-Packing Operations; First Edition; Reaffirmed, June 2016; ISO 13503-2:2006 This part of ISO 13503 provides standard testing procedures for evaluating proppants used in hydraulic fracturing and gravel-packing operations.

NOTE “Proppants” mentioned henceforth in this part of ISO 13503 refer to sand, ceramic media, resin-coated proppants, gravel-packing media and other materials used for hydraulic fracturing and gravel-packing operations.

The objective of this part of ISO 13503 is to provide a consistent methodology for testing performed on hydraulic fracturing and/or gravel-packing proppants.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5af6766c-1cca-4e16-b1c3-304a1493ae36.htm 01-May-08
ANSI/API RP 19D 1ST ED (E1) Measuring the Long-Term Conductivity of Proppants; First Edition This part of ISO 13503 provides standard testing procedures for evaluating proppants used in hydraulic fracturing and gravel-packing operations.

NOTE The “proppants” mentioned henceforth in this part of ISO 13503 refer to sand, ceramic media, resin-coated proppants, gravel packing media, and other materials used for hydraulic fracturing and gravel-packing operations.

The objective of this part of ISO 13503 is to provide consistent methodology for testing performed on hydraulic-fracturing and/or gravel-packing proppants. It is not intended for use in obtaining absolute values of proppant pack conductivities under downhole reservoir conditions.


http://compass.astm.org/DIGITAL_LIBRARY/3PC/cc7452b6-4aa6-44f8-bf46-1b44bfdbb91a.htm 01-May-08
ANSI/API RP 19D 1ST ED (E1) (R 2015) Measuring the Long-term Conductivity of Proppants; First Edition; Reaffirmed, May 2015: ISO 13503-5:2006 This part of ISO 13503 provides standard testing procedures for evaluating proppants used in hydraulic fracturing and gravel-packing operations.

NOTE The "proppants" mentioned henceforth in this part of ISO 13503 refer to sand, ceramic media, resin-coated proppants, gravel packing media, and other materials used for hydraulic fracturing and gravel-packing operations.

The objective of this part of ISO 13503 is to provide consistent methodology for testing performed on hydraulic-fracturing and/or gravel-packing proppants. It is not intended for use in obtaining absolute values of proppant pack conductivities under downhole reservoir conditions.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d4ddf2b5-c183-4786-a30a-a0c015e323dd.htm 01-May-15
ANSI/API RP 19G4 1ST ED (2011) Practices for Side-Pocket Mandrels and Related Equipment; First Edition; ISO 17078-4:2010 This part of ISO 17078 provides informative documentation to assist the user/purchaser and the supplier/manufacturer in specification, design, selection, testing, calibration, reconditioning, installation and use of side-pocket mandrels, flow-control devices and associated latches and installation tools. The product-design and manufacturing-related requirements for these products are included within the other parts of ISO 17078.

The content and coverage of several industry documents are compiled and refined within ISO 17078 (all parts).


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5327c1b2-8cf5-4880-b33c-1ce8af588157.htm 01-Jun-11
ANSI/API RP 19G4 1ST ED (R 2019) Practices for Side-Pocket Mandrels and Related Equipment; First Edition; R 2019; ISO 17078-4:2010 This part of ISO 17078 provides informative documentation to assist the user/purchaser and the supplier/manufacturer in specification, design, selection, testing, calibration, reconditioning, installation and use of side-pocket mandrels, flow-control devices and associated latches and installation tools. The product-design and manufacturing-related requirements for these products are included within the other parts of ISO 17078.

The content and coverage of several industry documents are compiled and refined within ISO 17078 (all parts).


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9984662b-6cf6-45de-8798-19c840e6632e.htm 01-Jun-11
ANSI/API RP 2MOP 1ST ED (E1) Marine Operations; First Edition; ISO 19901-6:2009 This part of ISO 19901 provides requirements and guidance for the planning and engineering of marine operations, encompassing the design and analysis of the components, systems, equipment and procedures required to perform marine operations, as well as the methods or procedures developed to carry them out safely.

This part of ISO 19901 is applicable to marine operations for offshore structures including

— steel and concrete gravity base structures (GBS);

— piled steel structures and compliant towers; — tension leg platforms (TLP);

— deep draught floaters (DDF), including spars or deep draught caisson vessels (DDCV);

— floating production semi-submersibles (FPSS);

— floating production, storage and offloading vessels (FPSO);

— other types of floating production systems (FPS);

— mobile offshore units (MOU);

— topsides and components of any of the above;

— subsea templates and similar structures;

— gravity, piled, drag embedded and suction or other anchors;

— tendon foundations;

— associated mooring systems.

This document is also applicable to modifications of existing structures, e.g. installation of additional topsides modules.

This part of ISO 19901 is not applicable to the following marine operations:

a) construction activities, e.g. in a fabrication yard onshore, where there is no exposure to the marine environment;

b) drilling, processing and petrochemical activities;

c) routine marine activities during the service life of the structure;

d) drilling from mobile offshore drilling units (MODU);

e) installation of pipelines, flowlines, risers and umbilicals;

f) diving.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c2d87846-0b01-47fa-b6c6-674c5c4d5a68.htm 01-Jul-10
ANSI/API RP 2N 3RD ED (2015) Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions; Third Edition; ISO 19906:2010 This standard specifies requirements and provides recommendations and guidance for the design, construction, transportation, installation, and removal of offshore structures, related to the activities of the petroleum and natural gas industries in arctic and cold regions. Reference to arctic and cold regions in this standard is deemed to include both the arctic and other cold regions that are subject to similar sea ice, iceberg, and icing conditions. The objective of this standard is to ensure that offshore structures in arctic and cold regions provide an appropriate level of reliability with respect to personnel safety, environmental protection, and asset value to the owner, to the industry, and to society in general.

This standard does not contain requirements for the operation, maintenance, service-life inspection, or repair of arctic and cold region offshore structures, except where the design strategy imposes specific requirements (e.g. 17.2.2).

While this standard does not apply specifically to mobile offshore drilling units (see ISO 19905-1), the procedures relating to ice actions and ice management contained herein are applicable to the assessment of such units.

This standard does not apply to mechanical, process, and electrical equipment or any specialized process equipment associated with arctic and cold region offshore operations except in so far as it is necessary for the structure to sustain safely the actions imposed by the installation, housing, and operation of such equipment.


http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3743415b-7041-4ac1-bdf9-18296482a7df.htm 01-Apr-15
ANSI/API RP 2TOP 1ST ED (2019) Topsides Structure; First Edition, August 2019; ISO 19901-3:2010 This document provides requirements for the design, fabrication, transportation, installation, modification, and structural integrity management for the topsides structure for an oil and gas platform; API 2TOP complements API 2A-WSD, API 2A-LRFD, ISO 19903, API 2FPS, API 2T, ISO 19905-1, and API 2N, which give requirements for various forms of substructures. It is based on ISO 19901-3:2010 (Corrected version, 15-Dec-2011) and is consistent with ISO 19901-3:2014 to the fullest extent possible and modified only where needed for API purposes. Requirements in this standard concerning modifications and maintenance relate only to those aspects that are of direct relevance to the structural integrity of the topsides structure. </p:>

The actions on the topsides structure and structural components are derived from this document and where necessary, in combination with API, other international standards and the ISO 19900 series. The resistances of structural components of the topsides structure are determined by the use of international or national building codes, as specified in this document. If the topsides structure is integrated with the supporting substructure to help resist global platform forces, the requirements of this standard are supplemented with applicable requirements of the associated substructure such as API 2A-LRFD for fixed steel structures and API 2FPS for floating structures. This document is applicable to:

For those parts of floating offshore structures and mobile offshore units that are chosen to be governed by the rules of a recognized classification society, the corresponding class rules supersede the associated requirements of this standard.

This document has limited guidance on corrosion control, alternate structural materials, and other miscellaneous topics that the structural engineer often has to consider.

This document contains requirements for, as well as guidance and information on, the following aspects of topsides structures:

This document applies to structural components including the following:

  • structural components in decks, module support frames, and modules;
  • flare structures;
  • crane pedestal and other crane support arrangements;
  • helicopter landing decks (helidecks);
  • permanent bridges between separate offshore structures;
  • masts, towers, and booms on offshore structures.
  • http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/63d990d1-a2d9-473e-8dfd-252d0a412ec2.htm 01-Aug-19
    ANSI/API RP 5C5 3RD ED (2003) Recommended Practice on Procedures for Testing Casing and Tubing Connections; Third Edition; ISO 13679:2002 This International Standard establishes minimum design verification testing procedures and acceptance criteria for casing and tubing connections for the oil and natural gas industries. These physical tests are part of a design verification process and provide objective evidence that the connection conforms to the manufacturer's claimed test load envelope and limit loads.

    It categorizes test severity into four test classes.

    It describes a system of identification codes for connections. This International Standard does not provide the statistical basis for risk analysis.

    This International Standard addresses only three of the five distinct types of primary loads to which casing and tubing strings are subjected in wells: fluid pressure (internal and/or external), axial force (tension or compression), bending (buckling and/or wellbore deviation), as well as make-up torsion. It does not address rotation torsion and non-axisymetric (area, line or point contact) loads.

    This International Standard specifies tests to be performed to determine the galling tendency, sealing performance and structural integrity of casing and tubing connections. The words casing and tubing apply to the service application and not to the diameter of the pipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/649d11bc-c49e-483a-bbe5-7d6e155ea7a4.htm 01-Jul-03
    ANSI/API RP 8B 7TH ED (A1) (A2) (R 2012) Recommended Practice for Procedures for Inspections, Maintenance, Repair and Remanufacture of Hoisting Equipment; Seventh Edition; Reaffirmed, August 2012 This International Standard gives guidelines and establishes requirements for inspection, maintenance, repair and remanufacture of items of hoisting equipment used in drilling and production operations, in order to maintain the serviceability of this equipment.

    Items of drilling and production hoisting equipment covered by this International Standard are:

    -crown-block sheaves and bearings; -travelling blocks and hook blocks; :

    -block-to-hook adapters; :

    -connectors and link adapters; :

    -drilling hooks; :

    -tubing hooks and sucker-rod hooks; :

    -elevator links; :

    -casing elevators, tubing elevators, drill-pipe elevators and drill-collar elevators; :

    -sucker-rod elevators; :

    -rotary swivel-bail adapters; :

    -rotary swivels; :

    -power swivels; :

    -power subs; :

    -spiders, if capable of being used as elevators; :

    dead-line tie-down/wireline anchors; :

    -drill-string motion compensators; :

    -kelly spinners, if capable of being used as hoisting equipment; :

    -riser-running tool components, if capable of being used as hoisting equipment; :

    -wellhead-running tool components, if capable of being used as hoisting equipment; :

    -safety clamps, capable of being used as hoisting equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f83994a3-a233-4f80-ad96-c44128063d45.htm 01-Aug-12
    ANSI/API RP 8B 8TH ED (2014) Recommended Practice for Procedures for Inspections, Maintenance, Repair and Remanufacture of Hoisting Equipment; Eighth Edition This document provides guidelines and establishes requirements for inspection, maintenance, repair, and remanufacture of items of hoisting equipment manufactured according to API 8A, API 8C, or ISO 13535 used in drilling and production operations, in order to maintain the serviceability of this equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a3b9b648-dbaf-499d-9df5-63525c56b475.htm 01-May-14
    ANSI/API RP 8B 8TH ED (A1) Recommended Practice for Procedures for Inspection, Maintenance, Repair and Remanufacture of Hoisting Equipment; Eighth Edition This document provides guidelines and establishes requirements for inspection, maintenance, repair, and remanufacture of items of hoisting equipment manufactured according to API 8A, API 8C, or ISO 13535 used in drilling and production operations, in order to maintain the serviceability of this equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/098549ff-5667-401f-ab3a-848d61a1b79c.htm 01-May-14
    ANSI/API RP 8B 8TH ED (E1) (A1) Recommended Practice for Procedures for Inspections, Maintenance, Repair, and Remanufacture of Hoisting Equipment; Eighth Edition This document provides guidelines and establishes requirements for inspection, maintenance, repair, and remanufacture of items of hoisting equipment manufactured according to API 8A, API 8C, or ISO 13535 used in drilling and production operations, in order to maintain the serviceability of this equipment. p>Items of drilling and production hoisting equipment covered are:

    • — crown-block sheaves and bearings;
    • — traveling blocks and hook blocks;
    • — traveling blocks and hook blocks;
    • — connectors and link adapters;
    • — drilling hooks;
    • — tubing hooks and sucker-rod hooks;
    • — elevator links;
    • — casing elevators, tubing elevators, drill-pipe elevators, and drill-collar elevators;
    • — sucker-rod elevators;
    • — rotary swivel-bail adapters;
    • — — power swivels;
    • — power subs;
    • — spiders, if capable of being used as elevators;
    • — dead-line tie-down/wireline anchors;
    • — riser-running tool components, if capable of being used as hoisting equipment;
    • — wellhead-running tool components, if capable of being used as hoisting equipment;
    • — safety clamps, capable of being used as hoisting equipment;
    • — top drives;
    • — casing running tools.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/423afd66-857d-4b04-a7c0-cb61271b4c2f.htm 01-Aug-19
    ANSI/API SPEC 10A 23RD ED (A1) Specification for Cements and Materials for Well Cementing; Twenty-Third Edition This standard specifies requirements and gives recommendations for eight classes of well cements, including their chemical and physical requirements and procedures for physical testing.

    This standard is applicable to well cement Classes A, B, C, D, E and F, which are the products obtained by grinding Portland cement clinker and, if needed, calcium sulfate as an interground additive. Processing additives may be used in the manufacture of cement of these classes. Suitable set-modifying agents may be interground or blended during manufacture of Classes D, E and F.

    This standard is also applicable to well cement Classes G and H, which are the products obtained by grinding Portland cement clinker with no additives other than calcium sulfate or water.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/b011ebef-fdb5-4307-a6a5-9f3ac5dc2ba8.htm 01-Apr-02
    ANSI/API SPEC 10A 24TH ED (2010) Specification for Cements and Materials for Well Cementing; Twenty-Fourth Edition This standard specifies requirements and gives recommendations for eight

    classes of well cements, including their chemical and physical requirements and procedures for physical testing.

    This standard is applicable to well cement Classes A, B, C, D, E and F, which are the products obtained by grinding Portland cement clinker and, if needed, calcium sulfate as an interground additive. Processing additives may be used in the manufacture of cement of these classes. Suitable set-modifying agents may be interground or blended during manufacture of Classes D, E and F.

    This standard is also applicable to well cement Classes G and H, which are the products obtained by grinding Portland cement clinker with no additives other than calcium sulfate or water.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/5d7667a4-e91e-475f-a2c0-659f979afebf.htm 01-Dec-10
    ANSI/API SPEC 10A 24TH ED (R 2015) Specification for Cements and Materials for Well Cementing; Twenty-Fourth Edition; Reaffirmed, April 2015; ISO 10426-1:2009 This standard specifies requirements and gives recommendations for eight

    classes of well cements, including their chemical and physical requirements and procedures for physical testing.

    This standard is applicable to well cement Classes A, B, C, D, E and F, which are the products obtained by grinding Portland cement clinker and, if needed, calcium sulfate as an interground additive. Processing additives may be used in the manufacture of cement of these classes. Suitable set-modifying agents may be interground or blended during manufacture of Classes D, E and F.

    This standard is also applicable to well cement Classes G and H, which are the products obtained by grinding Portland cement clinker with no additives other than calcium sulfate or water.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/45357ebb-202c-4292-979f-f3b4dbcc9680.htm 01-Dec-10
    ANSI/API SPEC 10A 25TH ED (2019) Specification for Cements and Materials for Well Cementing; Twenty-Fifth Edition This document specifies requirements and gives recommendations for six classes of well cements, including their chemical and physical requirements and procedures for physical testing.

    This specification is applicable to well cement classes A, B, C, and D, which are the products obtained by grinding Portland cement clinker and, if needed, calcium sulfate, as an interground additive. Processing additives can be used in the manufacture of cement of these classes. Suitable set-modifying agents can be interground or blended during manufacture of class D cement.

    This specification is also applicable to well cement classes G and H, which are the products obtained by grinding clinker with no additives other than one or more forms of calcium sulfate, water, or chemical additives as required for chromium (VI) reduction.

    This edition of Specification 10A is the identical national adoption of ISO 10426-1 (Identical), Petroleum and natural gas industries—Cements and materials for well cementing—Part 1: Specification (includes ISO errata).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6e3cf5b3-ccfe-4a73-8a23-f01c57c385d2.htm 01-Mar-19
    ANSI/API SPEC 10A 25TH ED (A1) Specification for Cements and Materials for Well Cementing; Twenty-Fifth Edition; Effective Date: September 2019 1 Scope

    1.1 General

    This document specifies requirements and gives recommendations for six classes of well cements, and two classes of composite well cements including their chemical and physical requirements, and procedures for physical testing.

    This specification is applicable to well cement classes A, B, C, and D, which are the products obtained by grinding Portland cement clinker and, if needed, calcium sulfate (CaSO4) as an interground additive. Processing additives can be used in the manufacture of cement of these classes. Suitable set-modifying agents can be interground or blended during the manufacture of Class D cement. Annex B describes composite well cement classes K and L, which are the products obtained by intergrinding Portland cement clinker and one or more forms of CaSO4 with composite constituents, or by subsequent blending of separately produced Portland cement with separately processed composite constituents. Composite constituents are also specified in Annex B.

    This specification is also applicable to well cement classes G and H, which are the products obtained by grinding clinker with no additives other than one or more forms of CaSO4, water, or chemical additives as required for chromium (VI) reduction.

    1.2 Application of the API Monogram

    When product is manufactured at a facility licensed by API and is intended to be supplied bearing the API Monogram, the requirements of Annex A shall apply.

    1.3 Use of Metric SI and US Customary Units

    This document contains metric SI and US customary oilfield units. For the purposes of this document, the conversion between the systems is not exact and has been intentionally rounded to allow for ease of use in calibration and measurement.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/82493435-f281-45d8-af82-07ad8131cb56.htm 01-Mar-19
    ANSI/API SPEC 10D 6TH ED (R 2015) Specification for Bow-string Casing Centralizers; Sixth Edition; Effective Date: September 1, 2002; Reaffirmed, April 2015 This standard provides minimum performance requirements, test procedures and marking requirements for bow-spring casing centralizers for the petroleum and natural gas industries. The requirements contained herein are limited, but are deemed adequate for use in oil field cementing. The procedures provide verification testing for the manufacturer's design, materials and process specifications, and periodic testing to confirm the consistency of product performance.

    This standard is not applicable to rigid or positive centralizers.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d4b92571-9ad0-4253-a96f-c64e041dc9fc.htm 01-Apr-15
    ANSI/API SPEC 11D1 2ND ED (2009) Packers and Bridge Plugs; Second Edition; Effective Date: January 1, 2010 This International Standard provides requirements and guidelines for packers and bridge plugs as defined herein for use in the petroleum and natural gas industry. This International Standard provides requirements for the functional specification and technical specification, including design, design verification and validation, materials, documentation and data control, repair, shipment, and storage. In addition, products covered by this International Standard apply only to applications within a conduit. Installation and maintenance of these products are outside the scope of this International Standard.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/18dae076-9b8a-4881-a235-d85e20034729.htm 01-Jul-09
    ANSI/API SPEC 11D1 3RD ED (2015) Packers and Bridge Plugs; Third Edition; ISO 14310:2008 This specification provides requirements and guidelines for packers and

    bridge plugs as defined herein for use in the petroleum and natural gas industry. This specification provides requirements for the functional specification and technical specification, including design, design verification and validation, materials, documentation and data control, repair, shipment, and storage. In addition, products covered by this specification apply only to applications within a conduit. Installation and maintenance of these products are outside the scope of this specification.

    This specification includes the following annexes:

    — Annex A: Use of API Monogram by Licensees;

    — Annex B: Requirements for HPHT Environment Equipment;

    — Annex C: Requirements for HPHT Environment Operational Tools;

    — Annex D: External Flow Testing Requirements.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/4828a454-0fea-451b-a61b-18304836ea91.htm 01-Apr-15
    ANSI/API SPEC 11D1 3RD ED (E1) Packers and Bridge Plugs; Third Edition; ISO 14310:2008 1 Scope

    This specification provides requirements and guidelines for packers and bridge plugs as defined herein for use in the petroleum and natural gas industry. This specification provides requirements for the functional specification and technical specification, including design, design verification and validation, materials, documentation and data control, repair, shipment, and storage. In addition, products covered by this specification apply only to applications within a conduit. Installation and maintenance of these products are outside the scope of this specification.

    This specification includes the following annexes:
    • Annex A: Use of API Monogram by Licensees;
    • Annex B: Requirements for HPHT Environment Equipment;
    • Annex C: Requirements for HPHT Environment Operational Tools;
    • Annex D: External Flow Testing Requirements.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b0401c20-05da-4deb-b94b-edbfd3160962.htm 01-Apr-15
    ANSI/API SPEC 13A 18TH ED (2010) Specification for Drilling Fluids Materials; Eighteenth Edition This International Standard covers physical properties and test procedures for materials manufactured for use in oil- and gas-well drilling fluids. The materials covered are barite, haematite, bentonite, nontreated bentonite, OCMA-grade bentonite, attapulgite, sepiolite, technical-grade low-viscosity carboxymethylcellulose (CMC-LVT), technical-grade high-viscosity carboxymethylcellulose (CMC-HVT), starch, low-viscosity polyanionic cellulose (PAC-LV), high-viscosity polyanionic cellulose (PAC-HV), drilling-grade Xanthan gum, and barite 4,1. This International Standard is intended for the use of manufacturers of named products.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/9e5d94fd-1ee1-49fe-a836-e4fbf3df5d72.htm 01-Feb-10
    ANSI/API SPEC 13A 18TH ED (E1) Specification for Drilling Fluids Materials; Eighteenth Edition This International Standard covers physical properties and test procedures for materials manufactured for use in oil- and gas-well drilling fluids. The materials covered are barite, haematite, bentonite, nontreated bentonite, OCMA-grade bentonite, attapulgite, sepiolite, technical-grade low-viscosity carboxymethylcellulose (CMC-LVT), technical-grade high-viscosity carboxymethylcellulose (CMC-HVT), starch, low-viscosity polyanionic cellulose (PAC-LV), high-viscosity polyanionic cellulose (PAC-HV), drilling-grade Xanthan gum, and barite 4,1. This International Standard is intended for the use of manufacturers of named products.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/e05d3152-d19b-4f40-bdec-679816fcc835.htm 01-Feb-10
    ANSI/API SPEC 13A 18TH ED (E1) (E2) Specification for Drilling Fluids Materials; Eighteenth Edition This International Standard covers physical properties and test procedures for materials manufactured for use in oil- and gas-well drilling fluids. The materials covered are barite, haematite, bentonite, nontreated bentonite, OCMA-grade bentonite, attapulgite, sepiolite, technical-grade low-viscosity carboxymethylcellulose (CMC-LVT), technical-grade high-viscosity carboxymethylcellulose (CMC-HVT), starch, low-viscosity polyanionic cellulose (PAC-LV), high-viscosity polyanionic cellulose (PAC-HV), drilling-grade Xanthan gum, and barite 4,1. This International Standard is intended for the use of manufacturers of named products.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/8f3a0193-35c1-40e1-b5b6-5abc1b968169.htm 01-Feb-10
    ANSI/API SPEC 13A 18TH ED (E1) (E2) (E3) Specification for Drilling Fluids Materials; Eighteenth Edition; ISO 13500:2009 This International Standard covers physical properties and test procedures

    for materials manufactured for use in oil- and gas-well drilling fluids. The materials covered are barite, haematite, bentonite, nontreated bentonite, OCMA-grade bentonite, attapulgite, sepiolite, technical-grade low-viscosity carboxymethylcellulose (CMC-LVT), technical-grade high-viscosity carboxymethylcellulose (CMC-HVT), starch, low-viscosity polyanionic cellulose (PAC-LV), high-viscosity polyanionic cellulose (PAC-HV), drilling-grade Xanthan gum, and barite 4,1. This International Standard is intended for the use of manufacturers of named products.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/6e794c1d-4422-4642-ad65-f26229440c5b.htm 01-Feb-10
    ANSI/API SPEC 13A 18TH ED (E1) (E2) (E3) (E4) Specification for Drilling Fluids Materials; Eighteenth Edition; ISO 13500:2009 This International Standard covers physical properties and test procedures

    for materials manufactured for use in oil- and gas-well drilling fluids. The materials covered are barite, haematite, bentonite, nontreated bentonite, OCMA-grade bentonite, attapulgite, sepiolite, technical-grade low-viscosity carboxymethylcellulose (CMC-LVT), technical-grade high-viscosity carboxymethylcellulose (CMC-HVT), starch, low-viscosity polyanionic cellulose (PAC-LV), high-viscosity polyanionic cellulose (PAC-HV), drilling-grade Xanthan gum, and barite 4,1. This International Standard is intended for the use of manufacturers of named products.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/7b52b5ab-84f8-4661-b7d8-06c94fd7e4b0.htm 01-Feb-10
    ANSI/API SPEC 13A 18TH ED (E1) (E2) (E3) (R 2015) Specification for Drilling Fluids Materials; Eighteenth Edition; ISO 13500:2009; Reaffirmed, July 2015 This International Standard covers physical properties and test procedures

    for materials manufactured for use in oil- and gas-well drilling fluids. The materials covered are barite, haematite, bentonite, nontreated bentonite, OCMA-grade bentonite, attapulgite, sepiolite, technical-grade low-viscosity carboxymethylcellulose (CMC-LVT), technical-grade high-viscosity carboxymethylcellulose (CMC-HVT), starch, low-viscosity polyanionic cellulose (PAC-LV), high-viscosity polyanionic cellulose (PAC-HV), drilling-grade Xanthan gum, and barite 4,1. This International Standard is intended for the use of manufacturers of named products.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/52a06856-a3b1-4c50-b7e0-52e94c76688c.htm 01-Feb-10
    ANSI/API SPEC 13A 19TH (2019) Specification for Drilling Fluids Materials; Nineteenth Edition; Effective: October 1, 2020 1 Scope

    This specification covers physical properties and test procedures for materials manufactured for use in oil- and gas-well drilling fluids. The materials covered are barite; hematite; bentonite; non-treated bentonite; attapulgite; sepiolite; technical grade, low-viscosity carboxymethyl cellulose (CMC-LVT); technical grade, high-viscosity carboxymethyl cellulose (CMC-HVT); starch; low-viscosity polyanionic cellulose (PAC-LV); high-viscosity polyanionic cellulose (PAC-HV); and drilling-grade xanthan gum. This specification is intended for the use of manufacturers, distributors, and end users of named products. Annex A (informative) contains information on the API Monogram Program and requirements for the approved use of the API Monogram by licensees.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/bc886601-b0f3-4401-9a2f-9def247aa267.htm 01-Oct-19
    ANSI/API SPEC 14A 10TH ED (2000) Specification for Subsurface Safety Valve Equipment; Tenth Edition This International Standard provides the minimum acceptable requirements for subsurface safety valves (SSSVs). It covers subsurface safety valves including all components that establish tolerances and/or clearances which may affect performance or interchangeability of the SSSVs. It includes repair operations and the interface connections to the flow control or other equipment, but does not cover the connections to the well conduit.

    NOTE Limits: The subsurface safety valve is an emergency safety device, and is not intended or designed for operational activities, such as production/injection reduction, production stop, or as a backflow valve.

    Redress activities are beyond the scope of this International Standard, see Clause 8.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/476be6a9-ee98-4159-a1b1-59f056879974.htm 01-Nov-00
    ANSI/API SPEC 14A 11TH ED (2005) Specification for Subsurface Safety Valve Equipment; Eleventh Edition This International Standard provides the minimum acceptable requirements for subsurface safety valves (SSSVs). It covers subsurface safety valves including all components that establish tolerances and/or clearances which may affect performance or interchangeability of the SSSVs. It includes repair operations and the interface connections to the flow control or other equipment, but does not cover the connections to the well conduit.

    NOTE Limits: The subsurface safety valve is an emergency safety device, and is not intended or designed for operational activities, such as production/injection reduction, production stop, or as a backflow valve.

    Redress activities are beyond the scope of this International Standard, see Clause 8.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/c70fe0b7-0f4a-43ef-9f75-7477fe2143a6.htm 01-Oct-05
    ANSI/API SPEC 14A 11TH ED (R 2012) Specification for Subsurface Safety Valve Equipment; Eleventh Edition; Reaffirmed, June 2012 This International Standard provides the minimum acceptable requirements for subsurface safety valves (SSSVs). It covers subsurface safety valves including all components that establish tolerances and/or clearances which may affect performance or interchangeability of the SSSVs. It includes repair operations and the interface connections to the flow control or other equipment, but does not cover the connections to the well conduit.

    NOTE Limits: The subsurface safety valve is an emergency safety device, and is not intended or designed for operational activities, such as production/injection reduction, production stop, or as a backflow valve.

    Redress activities are beyond the scope of this International Standard, see Clause 8.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/41ee85eb-f091-4b6f-b706-dc597915cdec.htm 01-Oct-05
    ANSI/API SPEC 14L 2ND ED (2007) Specification for Lock Mandrels and Landing Nipples; Second Edition This International Standard provides the requirements for lock mandrels and landing nipples within the production/injection conduit for the installation of flow control or other equipment used in the petroleum and natural gas industries. It includes the interface connections to the flow control or other equipment, but does not cover the connections to the well conduit.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/85ffe3e0-8519-4d4e-9e61-508be5098171.htm 01-Aug-07
    ANSI/API SPEC 14L 2ND ED (R 2012) Specification for Lock Mandrels and Landing Nipples; Second Edition; Reaffirmed, August 2012; ISO 16070:2005 This International Standard provides the requirements for lock mandrels and landing nipples within the production/injection conduit for the installation of flow control or other equipment used in the petroleum and natural gas industries. It includes the interface connections to the flow control or other equipment, but does not cover the connections to the well conduit.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/07efd0bc-a46c-41b3-8902-78c946f3dd10.htm 01-Aug-07
    ANSI/API SPEC 16A 3RD ED (E1) (S1) (R 2016) Specification for Drill-Through Equipment; Third Edition; Effective Date: December 1, 2004; Reaffirmed, August 2016; ISO 13533:2001 This American National Standard specifies requirements for performance,

    design, materials, testing and inspection, welding, marking, handling, storing and shipping of drill-through equipment used for drilling for oil and gas. It also defines service conditions in terms of pressure, temperature and wellbore fluids for which the equipment will be designed.

    This American National Standard is applicable to and establishes requirements for the following specific equipment:

    a) ram blowout preventers;

    b) ram blocks, packers and top seals;

    c) annular blowout preventers;

    d) annular packing units;

    e) hydraulic connectors;

    f) drilling spools;

    g) adapters;

    h) loose connections;

    i) clamps.

    Dimensional interchangeability is limited to end and outlet connections.

    Typical equipment defined by this American National Standard is shown in Figures 1 and 2; recommendations for failure reporting are outlined in annex F.

    This American National Standard does not apply to field use or field testing of drill-through equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/e95d20f4-172f-4ec4-b7b4-086451962f2d.htm 01-Jun-04
    ANSI/API SPEC 16A 3RD ED (R 2010) Specification for Drill-Through Equipment; Third Edition; Effective Date: December 1, 2004; Reaffirmed, August 2010; ISO 13533:2001 This American National Standard specifies requirements for performance,

    design, materials, testing and inspection, welding, marking, handling, storing and shipping of drill-through equipment used for drilling for oil and gas. It also defines service conditions in terms of pressure, temperature and wellbore fluids for which the equipment will be designed.

    This American National Standard is applicable to and establishes requirements for the following specific equipment:

    a) ram blowout preventers;

    b) ram blocks, packers and top seals;

    c) annular blowout preventers;

    d) annular packing units;

    e) hydraulic connectors;

    f) drilling spools;

    g) adapters;

    h) loose connections;

    i) clamps.

    Dimensional interchangeability is limited to end and outlet connections.

    Typical equipment defined by this American National Standard is shown in Figures 1 and 2; recommendations for failure reporting are outlined in annex F.

    This American National Standard does not apply to field use or field testing of drill-through equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/5f1969d3-70c4-41a3-9aa2-b3bf0534a2e2.htm 01-Jun-04
    ANSI/API SPEC 17D 2ND ED (2011) Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment; Second Edition; Effective Date: February 1, 2013 [for Valve and Actuator Design Validation (Test Requirements) Only] and November 1, 2011 [for All Other Requirements] This part of ISO 13628 provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. It specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.

    The user is responsible for ensuring subsea equipment meets any additional requirements of governmental regulations for the country in which it is installed. This is outside the scope of this part of ISO 13628.

    Where applicable, this part of ISO 13628 can also be used for equipment on satellite, cluster arrangements and multiple well template applications. Equipment that is within the scope of this part of ISO 13628 is listed as follows:

    a) subsea trees:

    — tree connectors and tubing hangers,

    — valves, valve blocks, and valve actuators,

    — chokes and choke actuators,

    — bleed, test and isolation valves,

    — TFL wye spool,

    — re-entry interface,

    — tree cap,

    — tree piping,

    — tree guide frames,

    — tree running tools,

    — tree cap running tools,

    — tree mounted flowline/umbilical connector,

    — tubing heads and tubing head connectors,

    — flowline bases and running/retrieval tools,

    — tree mounted controls interfaces (instrumentation, sensors, hydraulic tubing/piping and fittings, electrical controls cable and fittings);

    b) subsea wellheads:

    — conductor housings,

    — wellhead housings,

    — casing hangers,

    — seal assemblies,

    — guidebases,

    — bore protectors and wear bushings,

    — corrosion caps;

    c) mudline suspension systems:

    — wellheads,

    — running tools,

    — casing hangers,

    — casing hanger running tool,

    — tieback tools for subsea completion,

    — subsea completion adaptors for mudline wellheads,

    — tubing heads,

    — corrosion caps;

    d) drill through mudline suspension systems:

    — conductor housings,

    — surface casing hangers,

    — wellhead housings,

    — casing hangers,

    — annulus seal assemblies,

    — bore protectors and wear bushings,

    — abandonment caps;

    e) tubing hanger systems:

    — tubing hangers,

    — running tools;

    f) miscellaneous equipment:

    — flanged end and outlet connections,

    — clamp hub-type connections,

    — threaded end and outlet connections,

    — other end connections,

    — studs and nuts,

    — ring joint gaskets,

    — guideline establishment equipment.

    This part of ISO 13628 includes equipment definitions, an explanation of equipment use and function, an explanation of service conditions and product specification levels, and a description of critical components, i.e. those parts having requirements specified in this part of ISO 13628.

    The following equipment is outside the scope of this part of ISO 13628:

    — subsea wireline/coiled tubing BOPs;

    — installation, workover, and production risers;

    — subsea test trees (landing strings);

    — control systems and control pods;

    — platform tiebacks;

    — primary protective structures;

    — subsea process equipment;

    — subsea manifolding and jumpers;

    — subsea wellhead tools;

    — repair and rework;

    — multiple well template structures;

    — mudline suspension high pressure risers;

    — template piping;

    — template interfaces.

    This part of ISO 13628 is not applicable to the rework and repair of used equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d6141fa3-7963-42f5-9e49-c5b8498c70fa.htm 01-May-11
    ANSI/API SPEC 17D 2ND ED (E1) Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment; Second Edition; Effective Date: February 1, 2013 [for Valve and Actuator Design Validation (Test Requirements) Only] and November 1, 2011 [for All Other Requirements] This part of ISO 13628 provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. It specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.

    The user is responsible for ensuring subsea equipment meets any additional requirements of governmental regulations for the country in which it is installed. This is outside the scope of this part of ISO 13628.

    Where applicable, this part of ISO 13628 can also be used for equipment on satellite, cluster arrangements and multiple well template applications.

    Equipment that is within the scope of this part of ISO 13628 is listed as follows:

    a) subsea trees:

    — tree connectors and tubing hangers,

    — valves, valve blocks, and valve actuators,

    — chokes and choke actuators,

    — bleed, test and isolation valves,

    — TFL wye spool,

    — re-entry interface,

    — tree cap,

    — tree piping,

    — tree guide frames,

    — tree running tools,

    — tree cap running tools,

    — tree mounted flowline/umbilical connector,

    — tubing heads and tubing head connectors,

    — flowline bases and running/retrieval tools,

    — tree mounted controls interfaces (instrumentation, sensors, hydraulic tubing/piping and fittings, electrical controls cable and fittings);

    b) subsea wellheads:

    — conductor housings,

    — wellhead housings,

    — casing hangers,

    — seal assemblies,

    — guidebases,

    — bore protectors and wear bushings,

    — corrosion caps;

    c) mudline suspension systems:

    — wellheads,

    — running tools,

    — casing hangers,

    — casing hanger running tool,

    — tieback tools for subsea completion,

    — subsea completion adaptors for mudline wellheads,

    — tubing heads,

    — corrosion caps;

    d) drill through mudline suspension systems:

    — conductor housings,

    — surface casing hangers,

    — wellhead housings,

    — casing hangers,

    — annulus seal assemblies,

    — bore protectors and wear bushings,

    — abandonment caps;

    e) tubing hanger systems:

    — tubing hangers,

    — running tools;

    f) miscellaneous equipment:

    — flanged end and outlet connections,

    — clamp hub-type connections,

    — threaded end and outlet connections,

    — other end connections,

    — studs and nuts,

    — ring joint gaskets,

    — guideline establishment equipment.

    This part of ISO 13628 includes equipment definitions, an explanation of equipment use and function, an explanation of service conditions and product specification levels, and a description of critical components, i.e. those parts having requirements specified in this part of ISO 13628.

    The following equipment is outside the scope of this part of ISO 13628:

    — subsea wireline/coiled tubing BOPs;

    — installation, workover, and production risers;

    — subsea test trees (landing strings);

    — control systems and control pods;

    — platform tiebacks;

    — primary protective structures;

    — subsea process equipment;

    — subsea manifolding and jumpers;

    — subsea wellhead tools;

    — repair and rework;

    — multiple well template structures;

    — mudline suspension high pressure risers;

    — template piping;

    — template interfaces. This part of ISO 13628 is not applicable to the rework and repair of used equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/92dc4dcc-0c0e-4b88-873e-df4667812f9b.htm 01-May-11
    ANSI/API SPEC 17D 2ND ED (E1) (E2) (E3) Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment; Second Edition; Effective Date: February 1, 2013 [for Valve and Actuator Design Validation (Test Requirements) Only] and November 1, 2011 [for All Other Requirements] This part of ISO 13628 provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. It specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.

    The user is responsible for ensuring subsea equipment meets any additional requirements of governmental regulations for the country in which it is installed. This is outside the scope of this part of ISO 13628.

    Where applicable, this part of ISO 13628 can also be used for equipment on satellite, cluster arrangements and multiple well template applications. Equipment that is within the scope of this part of ISO 13628 is listed as follows:

    a) subsea trees:

    — tree connectors and tubing hangers,

    — valves, valve blocks, and valve actuators,

    — chokes and choke actuators,

    — bleed, test and isolation valves,

    — TFL wye spool,

    — re-entry interface,

    — tree cap,

    — tree piping,

    — tree guide frames,

    — tree running tools,

    — tree cap running tools,

    — tree mounted flowline/umbilical connector,

    — tubing heads and tubing head connectors,

    — flowline bases and running/retrieval tools,

    — tree mounted controls interfaces (instrumentation, sensors, hydraulic tubing/piping and fittings, electrical controls cable and fittings);

    b) subsea wellheads:

    — conductor housings,

    — wellhead housings,

    — casing hangers,

    — seal assemblies,

    — guidebases,

    — bore protectors and wear bushings,

    — corrosion caps;

    c) mudline suspension systems:

    — wellheads,

    — running tools,

    — casing hangers,

    — casing hanger running tool,

    — tieback tools for subsea completion,

    — subsea completion adaptors for mudline wellheads,

    — tubing heads,

    — corrosion caps;

    d) drill through mudline suspension systems:

    — conductor housings,

    — surface casing hangers,

    — wellhead housings,

    — casing hangers,

    — annulus seal assemblies,

    — bore protectors and wear bushings,

    — abandonment caps;

    e) tubing hanger systems:

    — tubing hangers,

    — running tools;

    f) miscellaneous equipment:

    — flanged end and outlet connections,

    — clamp hub-type connections,

    — threaded end and outlet connections,

    — other end connections,

    — studs and nuts,

    — ring joint gaskets,

    — guideline establishment equipment.

    This part of ISO 13628 includes equipment definitions, an explanation of equipment use and function, an explanation of service conditions and product specification levels, and a description of critical components, i.e. those parts having requirements specified in this part of ISO 13628.

    The following equipment is outside the scope of this part of ISO 13628:

    — subsea wireline/coiled tubing BOPs;

    — installation, workover, and production risers;

    — subsea test trees (landing strings);

    — control systems and control pods;

    — platform tiebacks;

    — primary protective structures;

    — subsea process equipment;

    — subsea manifolding and jumpers;

    — subsea wellhead tools;

    — repair and rework;

    — multiple well template structures;

    — mudline suspension high pressure risers;

    — template piping;

    — template interfaces.

    This part of ISO 13628 is not applicable to the rework and repair of used equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/52cd4f00-a9a1-4d3b-8bd5-442fc78fe32b.htm 01-May-11
    ANSI/API SPEC 17D 2ND ED (E1) (E2) (E3) (E4) (E5) Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment; Second Edition This part of ISO 13628 provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. It specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.

    The user is responsible for ensuring subsea equipment meets any additional requirements of governmental regulations for the country in which it is installed. This is outside the scope of this part of ISO 13628.

    Where applicable, this part of ISO 13628 can also be used for equipment on satellite, cluster arrangements and multiple well template applications. Equipment that is within the scope of this part of ISO 13628 is listed as follows:

    a) subsea trees:

    — tree connectors and tubing hangers,

    — valves, valve blocks, and valve actuators,

    — chokes and choke actuators,

    — bleed, test and isolation valves,

    — TFL wye spool,

    — re-entry interface,

    — tree cap,

    — tree piping,

    — tree guide frames,

    — tree running tools,

    — tree cap running tools,

    — tree mounted flowline/umbilical connector,

    — tubing heads and tubing head connectors,

    — flowline bases and running/retrieval tools,

    — tree mounted controls interfaces (instrumentation, sensors, hydraulic tubing/piping and fittings, electrical controls cable and fittings);

    b) subsea wellheads:

    — conductor housings,

    — wellhead housings,

    — casing hangers,

    — seal assemblies,

    — guidebases,

    — bore protectors and wear bushings,

    — corrosion caps;

    c) mudline suspension systems:

    — wellheads,

    — running tools,

    — casing hangers,

    — casing hanger running tool,

    — tieback tools for subsea completion,

    — subsea completion adaptors for mudline wellheads,

    — tubing heads,

    — corrosion caps;

    d) drill through mudline suspension systems:

    — conductor housings,

    — surface casing hangers,

    — wellhead housings,

    — casing hangers,

    — annulus seal assemblies,

    — bore protectors and wear bushings,

    — abandonment caps;

    e) tubing hanger systems:

    — tubing hangers,

    — running tools;

    f) miscellaneous equipment:

    — flanged end and outlet connections,

    — clamp hub-type connections,

    — threaded end and outlet connections,

    — other end connections,

    — studs and nuts,

    — ring joint gaskets,

    — guideline establishment equipment.

    This part of ISO 13628 includes equipment definitions, an explanation of equipment use and function, an explanation of service conditions and product specification levels, and a description of critical components, i.e. those parts having requirements specified in this part of ISO 13628.

    The following equipment is outside the scope of this part of ISO 13628:

    — subsea wireline/coiled tubing BOPs;

    — installation, workover, and production risers;

    — subsea test trees (landing strings);

    — control systems and control pods;

    — platform tiebacks;

    — primary protective structures;

    — subsea process equipment;

    — subsea manifolding and jumpers;

    — subsea wellhead tools;

    — repair and rework;

    — multiple well template structures;

    — mudline suspension high pressure risers;

    — template piping;

    — template interfaces.

    This part of ISO 13628 is not applicable to the rework and repair of used equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/5386bc46-1960-4353-a585-225d3d0cb45f.htm 01-May-11
    ANSI/API SPEC 17D 2ND ED (E1) (E2) (E3) (E4) (E5) (E6) Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment; Second Edition; Effective Date: February 1, 2013 [for Valve and Actuator Design Validation (Test Requirements) Only] and November 1, 2011 [for All Other Requirements] This part of ISO 13628 provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. It specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.

    The user is responsible for ensuring subsea equipment meets any additional requirements of governmental regulations for the country in which it is installed. This is outside the scope of this part of ISO 13628.

    Where applicable, this part of ISO 13628 can also be used for equipment on satellite, cluster arrangements and multiple well template applications.

    Equipment that is within the scope of this part of ISO 13628 is listed as follows:

    a) subsea trees:

    — tree connectors and tubing hangers,

    — valves, valve blocks, and valve actuators,

    — chokes and choke actuators,

    — bleed, test and isolation valves,

    — TFL wye spool,

    — re-entry interface,

    — tree cap,

    — tree piping,

    — tree guide frames,

    — tree running tools,

    — tree cap running tools,

    — tree mounted flowline/umbilical connector,

    — tubing heads and tubing head connectors,

    — flowline bases and running/retrieval tools,

    — tree mounted controls interfaces (instrumentation, sensors, hydraulic tubing/piping and fittings, electrical controls cable and fittings);

    b) subsea wellheads:

    — conductor housings,

    — wellhead housings,

    — casing hangers,

    — seal assemblies,

    — guidebases,

    — bore protectors and wear bushings,

    — corrosion caps;

    c) mudline suspension systems:

    — wellheads,

    — running tools,

    — casing hangers,

    — casing hanger running tool,

    — tieback tools for subsea completion,

    — subsea completion adaptors for mudline wellheads,

    — tubing heads,

    — corrosion caps;

    d) drill through mudline suspension systems:

    — conductor housings,

    — surface casing hangers,

    — wellhead housings,

    — casing hangers,

    — annulus seal assemblies,

    — bore protectors and wear bushings,

    — abandonment caps;

    e) tubing hanger systems:

    — tubing hangers,

    — running tools;

    f) miscellaneous equipment:

    — flanged end and outlet connections,

    — clamp hub-type connections,

    — threaded end and outlet connections,

    — other end connections,

    — studs and nuts,

    — ring joint gaskets,

    — guideline establishment equipment.

    This part of ISO 13628 includes equipment definitions, an explanation of equipment use and function, an explanation of service conditions and product specification levels, and a description of critical components, i.e. those parts having requirements specified in this part of ISO 13628.

    The following equipment is outside the scope of this part of ISO 13628:

    — subsea wireline/coiled tubing BOPs;

    — installation, workover, and production risers;

    — subsea test trees (landing strings);

    — control systems and control pods;

    — platform tiebacks;

    — primary protective structures;

    — subsea process equipment;

    — subsea manifolding and jumpers;

    — subsea wellhead tools;

    — repair and rework;

    — multiple well template structures;

    — mudline suspension high pressure risers;

    — template piping;

    — template interfaces.

    This part of ISO 13628 is not applicable to the rework and repair of used equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/5d0cca3e-f44f-48f1-b0fb-3bc9a2d811b8.htm 01-May-11
    ANSI/API SPEC 17D 2ND ED (E1) (E2) (E3) (E4) (E5) (E6) (E7) (A1) Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment; Second Edition; Effective Date: February 1, 2013 [for Valve and Actuator Design Validation (Test Requirements) Only] and November 1, 2011 [for All Other Requirements] This part of ISO 13628 provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. It specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.


    The user is responsible for ensuring subsea equipment meets any additional requirements of governmental regulations for the country in which it is installed. This is outside the scope of this part of ISO 13628.

    Where applicable, this part of ISO 13628 can also be used for equipment on satellite, cluster arrangements and multiple well template applications

    Equipment that is within the scope of this part of ISO 13628 is listed as follows:

    a) subsea trees:

    — tree connectors and tubing hangers,

    — valves, valve blocks, and valve actuators,

    — chokes and choke actuators,

    — bleed, test and isolation valves,

    — TFL wye spool,

    — re-entry interface,

    — tree cap,

    — tree piping,

    — tree guide frames,

    — tree running tools,

    — tree cap running tools,

    — tree mounted flow line/umbilical connector,

    — tubing heads and tubing head connectors,

    — flowline bases and running/retrieval tools,

    — ree mounted controls interfaces (instrumentation, sensors, hydraulic tubing/piping and fittings, electrical controls cable and fittings);


    — tree mounted controls interfaces (instrumentation, sensors, hydraulic tubing/piping and fittings, electrical controls cable and fittings);

    b) subsea wellheads:

    — conductor housings,

    — wellhead housings,

    — casing hangers,

    — seal assemblies,

    — guidebases,

    — bore protectors and wear bushings,

    — corrosion caps;

    c) mudline suspension systems:

    — wellheads,

    — running tools,

    — casing hangers,

    — casing hanger running tool,

    — tieback tools for subsea completion,

    — subsea completion adaptors for mudline wellheads,

    — tubing heads,

    — corrosion caps;

    d) drill through mudline suspension systems:

    — conductor housings,

    — surface casing hangers,

    — wellhead housings,

    — casing hangers,

    — annulus seal assemblies,

    — bore protectors and wear bushings,

    — abandonment caps; API SPECIFICATION 17D, ISO 13628-4 3

    e) tubing hanger systems:

    — tubing hangers,

    — running tools;

    f) miscellaneous equipment:

    — flanged end and outlet connections,

    — clamp hub-type connections,

    — threaded end and outlet connections,

    — other end connections,

    — studs and nuts,

    — ring joint gaskets,

    — guideline establishment equipment.

    This part of ISO 13628 includes equipment definitions, an explanation of equipment use and function, an explanation of service conditions and product specification levels, and a description of critical components, i.e. those parts having requirements specified in this part of ISO 13628.

    The following equipment is outside the scope of this part of ISO 13628:

    — subsea wireline/coiled tubing BOPs;

    — installation, workover, and production risers;

    — subsea test trees (landing strings);

    — control systems and control pods;

    — platform tiebacks;

    — primary protective structures;

    — subsea process equipment;

    — subsea manifolding and jumpers;

    — subsea wellhead tools;

    — repair and rework;

    — multiple well template structures;

    — mudline suspension high pressure risers;

    — template piping;

    — template interfaces.

    This part of ISO 13628 is not applicable to the rework and repair of used equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/08f80a3d-608d-4f2b-b4b7-b6cc995e8428.htm 01-Sep-15
    ANSI/API SPEC 17D 2ND ED (E1) (E2) (E3) (E4) (E5) (E6) (E7) (A1) (R 2018) Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment; Second Edition; Effective Date: February 1, 2013 [for Valve and Actuator Design Validation (Test Requirements) Only] and November 1, 2011 [for All Other Requirements] This part of ISO 13628 provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. It specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.


    The user is responsible for ensuring subsea equipment meets any additional requirements of governmental regulations for the country in which it is installed. This is outside the scope of this part of ISO 13628.

    Where applicable, this part of ISO 13628 can also be used for equipment on satellite, cluster arrangements and multiple well template applications

    Equipment that is within the scope of this part of ISO 13628 is listed as follows:

    a) subsea trees:

    — tree connectors and tubing hangers,

    — valves, valve blocks, and valve actuators,

    — chokes and choke actuators,

    — bleed, test and isolation valves,

    — TFL wye spool,

    — re-entry interface,

    — tree cap,

    — tree piping,

    — tree guide frames,

    — tree running tools,

    — tree cap running tools,

    — tree mounted flow line/umbilical connector,

    — tubing heads and tubing head connectors,

    — flowline bases and running/retrieval tools,

    — ree mounted controls interfaces (instrumentation, sensors, hydraulic tubing/piping and fittings, electrical controls cable and fittings);


    — tree mounted controls interfaces (instrumentation, sensors, hydraulic tubing/piping and fittings, electrical controls cable and fittings);

    b) subsea wellheads:

    — conductor housings,

    — wellhead housings,

    — casing hangers,

    — seal assemblies,

    — guidebases,

    — bore protectors and wear bushings,

    — corrosion caps;

    c) mudline suspension systems:

    — wellheads,

    — running tools,

    — casing hangers,

    — casing hanger running tool,

    — tieback tools for subsea completion,

    — subsea completion adaptors for mudline wellheads,

    — tubing heads,

    — corrosion caps;

    d) drill through mudline suspension systems:

    — conductor housings,

    — surface casing hangers,

    — wellhead housings,

    — casing hangers,

    — annulus seal assemblies,

    — bore protectors and wear bushings,

    — abandonment caps; API SPECIFICATION 17D, ISO 13628-4 3

    e) tubing hanger systems:

    — tubing hangers,

    — running tools;

    f) miscellaneous equipment:

    — flanged end and outlet connections,

    — clamp hub-type connections,

    — threaded end and outlet connections,

    — other end connections,

    — studs and nuts,

    — ring joint gaskets,

    — guideline establishment equipment.

    This part of ISO 13628 includes equipment definitions, an explanation of equipment use and function, an explanation of service conditions and product specification levels, and a description of critical components, i.e. those parts having requirements specified in this part of ISO 13628.

    The following equipment is outside the scope of this part of ISO 13628:

    — subsea wireline/coiled tubing BOPs;

    — installation, workover, and production risers;

    — subsea test trees (landing strings);

    — control systems and control pods;

    — platform tiebacks;

    — primary protective structures;

    — subsea process equipment;

    — subsea manifolding and jumpers;

    — subsea wellhead tools;

    — repair and rework;

    — multiple well template structures;

    — mudline suspension high pressure risers;

    — template piping;

    — template interfaces.

    This part of ISO 13628 is not applicable to the rework and repair of used equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5058cb65-436a-48f0-b506-543857063940.htm 01-Sep-15
    ANSI/API SPEC 17D 2ND ED (E1) (E2) (E3) (E4) (E5) (E6) (E7) (E8) (A1) (A2) (R 2018) Design and Operation of Subsea Production Systems - Subsea Wellhead and Tree Equipment; Second Edition; Effective Date: February 1, 2013 [for Valve and Actuator Design Validation (Test Requirements) Only] and November 1, 2011 [for All Other Requirements] 1 Scope

    This part of ISO 13628 provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. It specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.

    The user is responsible for ensuring subsea equipment meets any additional requirements of governmental regulations for the country in which it is installed. This is outside the scope of this part of ISO 13628.

    Where applicable, this part of ISO 13628 can also be used for equipment on satellite, cluster arrangements and multiple well template applications.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9e20c184-1c8a-4c79-b5bb-4f03a571debf.htm 01-Sep-15
    ANSI/API SPEC 17D 2ND ED (E1) (E2) (E3) (E4) (E5) (E6) (E7) (E8) (A1) (R 2018) Design and Operation of Subsea Production Systems - Subsea Wellhead and Tree Equipment; Second Edition; Effective Date: February 1, 2013 [for Valve and Actuator Design Validation (Test Requirements) Only] and November 1, 2011 [for All Other Requirements] 1 Scope

    This part of ISO 13628 provides specifications for subsea wellheads, mudline wellheads, drill-through mudline wellheads and both vertical and horizontal subsea trees. It specifies the associated tooling necessary to handle, test and install the equipment. It also specifies the areas of design, material, welding, quality control (including factory acceptance testing), marking, storing and shipping for both individual sub-assemblies (used to build complete subsea tree assemblies) and complete subsea tree assemblies.

    The user is responsible for ensuring subsea equipment meets any additional requirements of governmental regulations for the country in which it is installed. This is outside the scope of this part of ISO 13628.

    Where applicable, this part of ISO 13628 can also be used for equipment on satellite, cluster arrangements and multiple well template applications.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5987da79-64a2-4703-98c2-0482928ebf35.htm 01-Sep-15
    ANSI/API SPEC 17E 4TH ED (2010) Specification for Subsea Umbilicals; Fourth Edition This part of ISO 13628 specifies requirements and gives recommendations for

    the design, material selection, manufacture, design verification, testing, installation and operation of umbilicals and associated ancillary equipment for the petroleum and natural gas industries. Ancillary equipment does not include topside hardware. Topside hardware refers to any hardware that is not permanently attached to the umbilical, above the topside hang-off termination.

    This part of ISO 13628 applies to umbilicals containing components, such as electrical cables, optical fibres, thermoplastic hoses and metallic tubes, either alone or in combination.

    This part of ISO 13628 applies to umbilicals for static or dynamic service, with surface-surface, surface-subsea and subsea-subsea routings.

    This part of ISO 13628 does not apply to the associated component connectors, unless they affect the performance of the umbilical or that of its ancillary equipment.

    This part of ISO 13628 applies only to tubes with the following dimensions: wall thickness, t < 6 mm, internal diameter, ID < 50,8 mm (2 in). Tubular products greater than these dimensions can be regarded as pipe/linepipe and it is expected that they be designed and manufactured according to a recognised pipeline/linepipe standard.

    This part of ISO 13628 does not apply to a tube or hose rated lower than 7 MPa (1 015 psi).

    This part of ISO 13628 does not apply to electric cable voltage ratings above standard rated voltages U0 /U(Um) = 3,6/6(7,2) kV rms, where U0, U and Um are as defined in IEC 60502-1 and IEC 60502-2.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/a93e208b-e063-4e60-966f-49fcc86646e2.htm 01-Oct-10
    ANSI/API SPEC 17F 2ND ED (R 2011) Specification for Subsea Production Control Systems; Second Edition; Reaffirmed, April 2011; ISO 13628-6 This part of ISO 13628 is applicable to design, fabrication, testing,

    installation and operation of subsea production control systems.

    This part of ISO 13628 covers surface control system equipment, subsea-installed control system equipment and control fluids. This equipment is utilized for control of subsea production of oil and gas and for subsea water and gas injection services. Where applicable, this part of ISO 13628 can be used for equipment on multiple-well applications.

    This part of ISO 13628 establishes design standards for systems, subsystems, components and operating fluids in order to provide for the safe and functional control of subsea production equipment.

    This part of ISO 13628 contains various types of information related to subsea production control systems. They are

    — informative data that provide an overview of the architecture and general functionality of control systems for the purpose of introduction and information;

    — basic prescriptive data that shall be adhered to by all types of control system;

    — selective prescriptive data that are control-system-type sensitive and shall be adhered to only when they are relevant;

    — optional data or requirements that need be adopted only when considered necessary either by the purchaser or the vendor.

    In view of the diverse nature of the data provided, control system purchasers and specifiers are advised to select from this part of ISO 13628 only the provisions needed for the application at hand. Failure to adopt a selective approach to the provisions contained herein can lead to overspecification and higher purchase costs.

    Rework and repair of used equipment are beyond the scope of this part of ISO 13628.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/2a106e18-5019-4446-8651-9367ebe58fea.htm 01-Dec-06
    ANSI/API SPEC 17J 3RD ED (2008) Specification for Unbonded Flexible Pipe; Third Edition; Effective Date: November 4, 2014 This part of ISO 13628 defines the technical requirements for safe, dimensionally and functionally interchangeable flexible pipes that are designed and manufactured to uniform standards and criteria. Minimum requirements are specified for the design, material selection, manufacture, testing, marking and packaging of flexible pipes, with reference to existing codes and standards where applicable. See ISO 13628-11 for guidelines on the use of flexible pipes and ancillary components.

    This part of ISO 13628 applies to unbonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. This part of ISO 13628 does not cover flexible pipes of bonded structure. This part of ISO 13628 does not apply to flexible pipe ancillary components. Guidelines for bend stiffeners and bend restrictors are given in Annex B.

    NOTE 1 Guidelines for other components are given in ISO 13628-11.

    This part of ISO 13628 does not apply to flexible pipes that include non-metallic tensile armour wires. Pipes of such construction are considered as prototype products subject to qualification testing.

    The applications addressed by this part of ISO 13628 are sweet and sour service production, including export and injection applications. Production products include oil, gas, water and injection chemicals. This part of ISO 13628 applies to both static and dynamic flexible pipes used as flowlines, risers and jumpers. This part of ISO 13628 does not apply to flexible pipes for use in choke-and-kill line applications.

    NOTE 2 See API Specification 16C for choke-and-kill line applications.

    NOTE 3 ISO 13628-10 provides guidelines for bonded flexible pipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ac72a49d-138c-4f7f-a491-6151b6d2c9c3.htm 01-Jul-08
    ANSI/API SPEC 17J 4TH ED (E1) Specification for Unbonded Flexible Pipe; Fourth Edition; Effective Date: November 4, 2014 This part of ISO 13628 defines the technical requirements for safe,

    dimensionally and functionally interchangeable flexible pipes that are designed and manufactured to uniform standards and criteria. Minimum requirements are specified for the design, material selection, manufacture, testing, marking and packaging of flexible pipes, with reference to existing codes and standards where applicable. See ISO 13628-11 for guidelines on the use of flexible pipes and ancillary components.

    This part of ISO 13628 applies to unbonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. This part of ISO 13628 does not cover flexible pipes of bonded structure. This part of ISO 13628 does not apply to flexible pipe ancillary components. Guidelines for bend stiffeners and bend restrictors are given in Annex B.

    NOTE 1 Guidelines for other components are given in ISO 13628-11.

    This part of ISO 13628 does not apply to flexible pipes that include non-metallic tensile armour wires. Pipes of such construction are considered as prototype products subject to qualification testing.

    The applications addressed by this part of ISO 13628 are sweet and sour service production, including export and injection applications. Production products include oil, gas, water and injection chemicals. This part of ISO 13628 applies to both static and dynamic flexible pipes used as flowlines, risers and jumpers. This part of ISO 13628 does not apply to flexible pipes for use in choke-and-kill line applications.

    NOTE 2 See API Specification 16C for choke-and-kill line applications.

    NOTE 3 ISO 13628-10 provides guidelines for bonded flexible pipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/c5a7a985-7af1-45c3-a313-e3511aefb464.htm 01-May-14
    ANSI/API SPEC 17J 4TH ED (E1) (E2) Specification for Unbonded Flexible Pipe; Fourth Edition; Effective Date: November 4, 2014 This part of ISO 13628 defines the technical requirements for safe,

    dimensionally and functionally interchangeable flexible pipes that are designed and manufactured to uniform standards and criteria. Minimum requirements are specified for the design, material selection, manufacture, testing, marking and packaging of flexible pipes, with reference to existing codes and standards where applicable. See ISO 13628-11 for guidelines on the use of flexible pipes and ancillary components.

    This part of ISO 13628 applies to unbonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. This part of ISO 13628 does not cover flexible pipes of bonded structure. This part of ISO 13628 does not apply to flexible pipe ancillary components. Guidelines for bend stiffeners and bend restrictors are given in Annex B.

    NOTE 1 Guidelines for other components are given in ISO 13628-11.

    This part of ISO 13628 does not apply to flexible pipes that include non-metallic tensile armour wires. Pipes of such construction are considered as prototype products subject to qualification testing.

    The applications addressed by this part of ISO 13628 are sweet and sour service production, including export and injection applications. Production products include oil, gas, water and injection chemicals. This part of ISO 13628 applies to both static and dynamic flexible pipes used as flowlines, risers and jumpers. This part of ISO 13628 does not apply to flexible pipes for use in choke-and-kill line applications.

    NOTE 2 See API Specification 16C for choke-and-kill line applications.

    NOTE 3 ISO 13628-10 provides guidelines for bonded flexible pipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/4e654a97-5bbb-40e2-95ea-2287b3d72fa8.htm 01-May-14
    ANSI/API SPEC 17J 4TH ED (E1) (E2) (A1) Specification for Unbonded Flexible Pipe; Fourth Edition; Effective Date: November 4, 2014 This part of ISO 13628 defines the technical requirements for safe,

    dimensionally and functionally interchangeable flexible pipes that are designed and manufactured to uniform standards and criteria. Minimum requirements are specified for the design, material selection, manufacture, testing, marking and packaging of flexible pipes, with reference to existing codes and standards where applicable. See ISO 13628-11 for guidelines on the use of flexible pipes and ancillary components.

    This part of ISO 13628 applies to unbonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. This part of ISO 13628 does not cover flexible pipes of bonded structure. This part of ISO 13628 does not apply to flexible pipe ancillary components. Guidelines for bend stiffeners and bend restrictors are given in Annex B.

    NOTE 1 Guidelines for other components are given in ISO 13628-11.

    This part of ISO 13628 does not apply to flexible pipes that include non-metallic tensile armour wires. Pipes of such construction are considered as prototype products subject to qualification testing.

    The applications addressed by this part of ISO 13628 are sweet and sour service production, including export and injection applications. Production products include oil, gas, water and injection chemicals. This part of ISO 13628 applies to both static and dynamic flexible pipes used as flowlines, risers and jumpers. This part of ISO 13628 does not apply to flexible pipes for use in choke-and-kill line applications.

    NOTE 2 See API Specification 16C for choke-and-kill line applications.

    NOTE 3 ISO 13628-10 provides guidelines for bonded flexible pipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0b883834-cf6e-4cbd-ab22-2ac961bab35c.htm 01-May-14
    ANSI/API SPEC 17K 2ND ED (R 2010) Specification for Bonded Flexible Pipe; Second Edition; Effective Date: May 1, 2006; Reaffirmed, May 2010; ISO 13628-10 1.1 Purpose

    1.1.1 This part of ISO 13628 defines the technical requirements for safe, dimensionally and functionally interchangeable bonded flexible pipes that are designed and manufactured to uniform standards and criteria. See Figure 1 for explanatory figure on typical bonded flexible pipe.

    1.1.2 Minimum requirements are specified for the design, material selection, manufacture, testing, marking and packaging of bonded flexible pipes, with reference to existing codes and standards where applicable. See API RP 17B for guidelines on the use of flexible pipes and ancillary components.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/dae8f8e6-c772-4993-b143-57da336f7b97.htm 01-Nov-05
    ANSI/API SPEC 17K 2ND ED (R 2016) Specification for Bonded Flexible Pipe; Second Edition; Effective Date: May 1, 2006; Reaffirmed, September 2016; ISO 13628-10 1.1 Purpose

    1.1.1 This part of ISO 13628 defines the technical requirements for safe, dimensionally and functionally interchangeable bonded flexible pipes that are designed and manufactured to uniform standards and criteria. See Figure 1 for explanatory figure on typical bonded flexible pipe.

    1.1.2 Minimum requirements are specified for the design, material selection, manufacture, testing, marking and packaging of bonded flexible pipes, with reference to existing codes and standards where applicable. See API RP 17B for guidelines on the use of flexible pipes and ancillary components.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/9908459e-ec3a-426c-8883-a9d8ae611c75.htm 01-Nov-05
    ANSI/API SPEC 19AC 1ST ED (2016) Specification for Completion Accessories; First Edition; ISO 14998:2013(E) This International Standard provides requirements and guidelines for completion accessories, as defined herein, for use in the petroleum and natural gas industry. This International Standard provides requirements for the functional specification and technical specifications, including design, design verification and validation, materials, documentation and data control, quality requirements, redress, repair, shipment, and storage. This International Standard covers the pressure-containing, nonpressure-containing, load-bearing, disconnect/reconnect, tubing-movement, and opening-a-port functionalities of completion accessories.

    Products covered under another API or international specification are not included. Also not included are other products such as liner/tubing hangers, downhole well test tools, inflow control devices, surface-controlled downhole chokes, downhole artificial lift equipment, control lines and fittings, and all functionalities relating to electronics or fiber optics. This International Standard does not cover the connections to the well conduit. Installation, application, and operation of these products are outside the scope of this International Standard.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a81eacc9-ee23-46ab-b38c-ec27a66a964e.htm 01-Sep-16
    ANSI/API SPEC 19G1 1ST ED (2010) Side-Pocket Mandrels; First Edition This part of ISO 17078 provides requirements for side-pocket mandrels used in the petroleum and natural gas industry. This part of ISO 17078 includes specifying, selecting, designing, manufacturing, quality control, testing, and preparation for shipping of side-pocket mandrels.

    This part of ISO 17078 does not address nor include requirements for end connections between the side-pocket mandrels and the well conduit. The installation and retrieval of side-pocket mandrels is outside the scope of this part of ISO 17078. Additionally, this part of ISO 17078 does not include specifications for centre-set mandrels, or mandrels that employ or support tubing-retrievable flow control devices.

    This part of ISO 17078 does not include gas-lift or any other flow-control valves or devices, latches, and/or associated wire line equipment that can or cannot be covered in other ISO specifications.

    The side-pocket mandrels to which this part of ISO 17078 refers are independent devices that can accept installation of flow-control or other devices down-hole.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/6d815786-6688-4e65-bc3a-1c0bcb71f7d1.htm 01-May-10
    ANSI/API SPEC 19G1 1ST ED (E1) Side-Pocket Mandrels; First Edition; ISO 17078-1:2004 This part of ISO 17078 provides requirements for side-pocket mandrels used in the petroleum and natural gas industry. This part of ISO 17078 includes specifying, selecting, designing, manufacturing, quality control, testing, and preparation for shipping of side-pocket mandrels.

    This part of ISO 17078 does not address nor include requirements for end connections between the side-pocket mandrels and the well conduit. The installation and retrieval of side-pocket mandrels is outside the scope of this part of ISO 17078. Additionally, this part of ISO 17078 does not include specifications for centre-set mandrels, or mandrels that employ or support tubing-retrievable flow control devices.

    This part of ISO 17078 does not include gas-lift or any other flow-control valves or devices, latches, and/or associated wire line equipment that can or cannot be covered in other ISO specifications.

    The side-pocket mandrels to which this part of ISO 17078 refers are independent devices that can accept installation of flow-control or other devices down-hole.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/4fa857e2-9220-40af-849a-81b53611c4f3.htm 01-May-10
    ANSI/API SPEC 19G2 1ST ED (2010) Flow-Control Devices for Side-Pocket Mandrels; First Edition; ISO 17078-2:2007 This part of ISO 17078 provides requirements for subsurface flow-control devices used in side-pocket mandrels (hereafter called flow-control devices) intended for use in the worldwide petroleum and natural gas industry. This includes requirements for specifying, selecting, designing, manufacturing, quality-control, testing and preparation for shipping of flow-control devices. Additionally, it includes information regarding performance testing and calibration procedures.

    The installation and retrieval of flow-control devices is outside the scope of this part of ISO 17078. Additionally, this part of ISO 17078 is not applicable to flow-control devices used in centre-set mandrels or with tubing-retrievable applications.

    This part of ISO 17078 does not include requirements for side-pocket mandrels, running, pulling, and kick-over tools, and latches that might or might not be covered in other ISO specifications. Reconditioning of used flow-control devices is outside of the scope of this part of ISO 17078.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/3e91fb83-a9cf-47d1-8d41-c5dd185727c9.htm 01-Jun-10
    ANSI/API SPEC 19G2 1ST ED (A1) Flow-Control Devices for Side-Pocket Mandrels; First Edition; ISO 17078-2:2007 This part of ISO 17078 provides requirements for subsurface flow-control devices used in side-pocket mandrels (hereafter called flow-control devices) intended for use in the worldwide petroleum and natural gas industry. This includes requirements for specifying, selecting, designing, manufacturing, quality-control, testing and preparation for shipping of flow-control devices. Additionally, it includes information regarding performance testing and calibration procedures.

    The installation and retrieval of flow-control devices is outside the scope of this part of ISO 17078. Additionally, this part of ISO 17078 is not applicable to flow-control devices used in centre-set mandrels or with tubing-retrievable applications.

    This part of ISO 17078 does not include requirements for side-pocket mandrels, running, pulling, and kick-over tools, and latches that might or might not be covered in other ISO specifications. Reconditioning of used flow-control devices is outside of the scope of this part of ISO 17078.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/57429350-81eb-46a4-bbdd-43b0763dc8ce.htm 01-Jun-10
    ANSI/API SPEC 19G3 1ST ED (2011) Running Tools, Pulling Tools, and Kick-Over Tools and Latches for Side-Pocket Mandrels; First Edition; ISO 17078-3:2009 This part of ISO 17078 provides requirements and guidelines for running tools, pulling tools, kick-over tools and latches used for the installation and retrieval of flow control and other devices to be installed in side-pocket mandrels for use in the petroleum and natural gas industries. This includes requirements for specifying, selecting, designing, manufacturing, quality control, testing and preparation for shipping of these tools and latches. Additionally, it includes information regarding performance testing and calibration procedures.

    The processes of installation, retrieval, maintenance and reconditioning of used running, pulling and kick-over tools and latches are outside the scope of this part of ISO 17078. Centre-set and tubing-retrievable mandrel applications are not covered.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/481bab2e-4591-4b73-9ee2-75bfa17adff2.htm 01-Jun-11
    ANSI/API SPEC 19G3 1ST ED (R 2019) Running Tools, Pulling Tools, and Kick-Over Tools and Latches for Side-Pocket Mandrels; First Edition; ISO 17078-3:2009 1 SCOPE

    This part of ISO 17078 provides requirements and guidelines for running tools, pulling tools, kick-over tools and latches used for the installation and retrieval of flow control and other devices to be installed in side-pocket mandrels for use in the petroleum and natural gas industries. This includes requirements for specifying, selecting, designing, manufacturing, quality control, testing and preparation for shipping of these tools and latches. Additionally, it includes information regarding performance testing and calibration procedures.

    The processes of installation, retrieval, maintenance and reconditioning of used running, pulling and kick-over tools and latches are outside the scope of this part of ISO 17078. Centre-set and tubing-retrievable mandrel applications are not covered.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5dcb4341-7750-4a04-8278-1f224512a6b9.htm 01-Jun-11
    ANSI/API SPEC 19SS 1ST ED (2018) Sand Screens; First Edition; ISO 17824:2009 This International Standard provides the requirements and guidelines for sand screens for use in the petroleum and natural gas industry. Included are the requirements for design, design validation, manufacturing, quality, storage and transport. The requirements of this International Standard are applicable to wire-wrap screens, pre-pack screens, and metal-mesh screens as defined herein.

    Annex A contains requirements for equipment to be provided with the API monogram.

    The following items are outside the scope of this International Standard:

    expandable sand screens, compliant sand screens, slotted liners, or tubing and accessory items such as centralizers or bull plugs;

    shunt screen technology, inflow control devices, downhole sensors, and selective isolation devices, even where they can be an integral part of the sand screen;

    analysis for sand retention efficiency;

    end connections of the basepipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/361fc1e4-f9f3-4db5-beaa-03c34451a6bd.htm 01-Jul-18
    ANSI/API SPEC 19SS 1ST ED (E1) Sand Screens; First Edition; ISO 17824:2009 This International Standard provides the requirements and guidelines for sand screens for use in the petroleum and natural gas industry. Included are the requirements for design, design validation, manufacturing, quality, storage and transport. The requirements of this International Standard are applicable to wire-wrap screens, pre-pack screens, and metal-mesh screens as defined herein.

    Annex A contains requirements for equipment to be provided with the API monogram.

    The following items are outside the scope of this International Standard:

    expandable sand screens, compliant sand screens, slotted liners, or tubing and accessory items such as centralizers or bull plugs;

    shunt screen technology, inflow control devices, downhole sensors, and selective isolation devices, even where they can be an integral part of the sand screen;

    analysis for sand retention efficiency;

    end connections of the basepipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/bfb55dce-cc0d-4325-8ad2-7bde3b52c9e7.htm 01-Jul-18
    ANSI/API SPEC 19V 1ST ED (2013) Subsurface Barrier Valves and Related Equipment; First Edition; ISO 28781:2010 This International Standard provides the requirements for subsurface barrier valves and related equipment as they are defined herein for use in the petroleum and natural gas industries. Included are the requirements for design, design validation, manufacturing, functional evaluation, repair, redress, handling and storage. Subsurface barrier valves provide a means of isolating the formation or creating a barrier in the tubular to facilitate the performance of pre- and/or post-production/injection operational activities in the well.

    The subsurface barrier valve is not designed as an emergency or fail-safe flow controlling safety device.

    This International Standard does not cover installation and maintenance, control systems such as computer systems, and control conduits not integral to the barrier valve. Also not included are products covered under ISO 17078, ISO 16070, ISO 14310, ISO 10432, ISO 10423 and the following products: downhole chokes, wellhead plugs, sliding sleeves, casing-mounted flow-control valves, injection valves, well-condition-activated valves or drill-stem test tools. This International Standard does not cover the connections to the well conduit.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/7486c987-d04e-4db6-ae4d-56fe6364d052.htm 01-May-13
    ANSI/API SPEC 5CRA 1ST ED (2010) Specification for Corrosion Resistant Alloy Seamless Tubes for Use as Casing, Tubing and Coupling Stock; First Edition; Effective Date: August 1, 2010; ISO 13680:2008 This International Standard specifies the technical delivery conditions for corrosion-resistant alloy seamless tubulars for casing, tubing and coupling stock for two product specification levels:

    — PSL-1, which is the basis of this International Standard;

    — PSL-2, which provides additional requirements for a product that is intended to be both corrosion resistant and cracking resistant for the environments and qualification method specified in ISO 15156-3 and Annex G of this International Standard.

    At the option of the manufacturer, PSL-2 products can be provided in lieu of PSL-1.

    NOTE 1 The corrosion-resistant alloys included in this International Standard are special alloys in accordance with ISO 4948-1 and ISO 4948-2.

    This International Standard is applicable to the following four groups of product:

    a) group 1, which is comprised of stainless alloys with a martensitic or martensitic/ferritic structure;

    b) group 2, which is comprised of stainless alloys with a ferritic-austenitic structure, such as duplex and superduplex stainless alloy;

    c) group 3, which is comprised of stainless alloys with an austenitic structure (iron base);

    d) group 4, which is comprised of nickel-based alloys with an austenitic structure (nickel base). This International Standard contains no provisions relating to the connection of individual lengths of pipe.

    NOTE 2 The connection or joining method can influence the corrosion performance of the materials specified in this International Standard.

    NOTE 3 It is necessary to recognize that not all PSL-1 categories and grades can be made cracking resistant per ISO 15156-3 and are, therefore, not included in PSL-2.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/a15fab05-f912-4fa1-b459-bb6bf3e14375.htm 01-Feb-10
    ANSI/API SPEC 5CRA 1ST ED (E1) (R 2015) Specification for Corrosion-resistant Alloy Seamless Tubes for Use as Casing, Tubing, and Coupling Stock; First Edition; Effective Date: August 1, 2010; Reaffirmed, April 2015; ISO 13680:2008 This International Standard specifies the technical delivery conditions for corrosion-resistant alloy seamless tubulars for casing, tubing and coupling stock for two product specification levels:

    — PSL-1, which is the basis of this International Standard;

    — PSL-2, which provides additional requirements for a product that is intended to be both corrosion resistant and cracking resistant for the environments and qualification method specified in ISO 15156-3 and Annex G of this International Standard.

    At the option of the manufacturer, PSL-2 products can be provided in lieu of PSL-1.

    NOTE 1 The corrosion-resistant alloys included in this International Standard are special alloys in accordance with ISO 4948-1 and ISO 4948-2.

    This International Standard is applicable to the following four groups of product:

    a) group 1, which is comprised of stainless alloys with a martensitic or martensitic/ferritic structure;

    c) group 3, which is comprised of stainless alloys with an austenitic structure (iron base);

    d) group 4, which is comprised of nickel-based alloys with an austenitic structure (nickel base).

    This International Standard contains no provisions relating to the connection of individual lengths of pipe.

    NOTE 2 The connection or joining method can influence the corrosion performance of the materials specified in this International Standard.

    NOTE 3 It is necessary to recognize that not all PSL-1 categories and grades can be made cracking resistant per ISO 15156-3 and are, therefore, not included in PSL-2.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/e0848643-a938-405d-a214-e02415819ad8.htm 01-Apr-15
    ANSI/API SPEC 5DP 1ST ED (R 2015) Specification for Drill Pipe; First Edition; Reaffirmed, April 2015 This International Standard specifies the technical delivery conditions for steel drill-pipes with upset pipe-body ends and weld-on tool joints for use in drilling and production operations in petroleum and natural gas industries for three product specification levels (PSL-1, PSL-2 and PSL-3). The requirements for PSL-1 form the basis of this International Standard. The requirements that define different levels of standard technical requirements for PSL-2 and PSL-3 are in Annex G.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b7caeefb-39d7-474b-960c-070c721d1b20.htm 01-Apr-15
    ANSI/API SPEC 6A 19TH ED (E1) (E2) (E3) (E4) (E5) (A1) (A2) (A3) (A4) Specification for Wellhead and Christmas Tree Equipment; Nineteenth Edition 1.1 Purpose

    This International Standard specifies requirements and gives recommendations for the performance, dimensional and functional interchangeability, design, materials, testing, inspection, welding, marking, handling, storing, shipment, purchasing, repair and remanufacture of wellhead and christmas tree equipment for use in the petroleum and natural gas industries.

    This International Standard does not apply to field use, field testing or field repair of wellhead and christmas tree equipment.

    1.2 Applicability

    This International Standard is applicable to the following specific equipment:

    a) wellhead equipment:

    — casing-head housings,

    — casing-head spools,

    — tubing-head spools,

    — cross-over spools,

    — multi-stage head housings and spools;

    b) connectors and fittings:

    — cross-over connectors,

    — tubing-head adapters,

    — top connectors,

    — tees and crosses,

    — fluid-sampling devices,

    — adapter and spacer spools;

    c) casing and tubing hangers:

    — mandrel hangers,

    — slip hangers;

    d) valves and chokes:

    — single valves,

    — multiple valves,

    — actuated valves,

    — valves prepared for actuators,

    — check valves,

    — chokes,

    — surface and underwater safety valves and actuators,

    — back-pressure valves;

    e) loose connectors [flanged, threaded, other end connectors (OEC), and welded]:

    — weld neck connectors,

    — blind connectors,

    — threaded connectors,

    — adapter and spacer connectors,

    — bullplugs,

    — valve-removal plugs;

    f) other equipment:

    — actuators,

    — clamp hubs,

    — pressure boundary penetrations,

    — ring gaskets,

    — running and testing tools (see Annex H),

    — wear bushings (see Annex H).

    The nomenclature used in this International Standard for typical equipment is shown in Figures 1 and 2. All parts whose physical dimensions conform to the metric tables incorporated into the body of this International Standard or to the tables in USC units in Annex B are acceptable; see Introduction.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/6e3f8ed1-0aeb-4af9-b966-ba28a3a64f78.htm 01-Jul-04
    ANSI/API SPEC 6A 20TH ED (E1) (E2) (E3) (E4) (E5) (E6) (E7) (A1) (A2) (A3) Specification for Wellhead and Christmas Tree Equipment; Twentieth Edition; Effective Date: April 1, 2011 1.1 Purpose

    This International Standard specifies requirements and gives recommendations for the performance, dimensional and functional interchangeability, design, materials, testing, inspection, welding, marking, handling, storing, shipment, purchasing, repair and remanufacture of wellhead and christmas tree equipment for use in the petroleum and natural gas industries.

    This International Standard does not apply to field use, field testing or field repair of wellhead and christmas tree equipment.

    1.2 Applicability

    This International Standard is applicable to the following specific equipment:

    a) wellhead equipment:

    — casing-head housings,

    — casing-head spools,

    — tubing-head spools,

    — cross-over spools,

    — multi-stage head housings and spools;

    b) connectors and fittings:

    — cross-over connectors,

    — tubing-head adapters,

    — top connectors,

    — tees and crosses,

    — fluid-sampling devices,

    — adapter and spacer spools;

    c) casing and tubing hangers:

    — mandrel hangers,

    — slip hangers;

    d) valves and chokes:

    — single valves,

    — multiple valves,

    — actuated valves,

    — valves prepared for actuators,

    — check valves,

    — chokes,

    — surface and underwater safety valves and actuators,

    — back-pressure valves;

    e) loose connectors [flanged, threaded, other end connectors (OEC), and welded]:

    — weld neck connectors,

    — blind connectors,

    — threaded connectors,

    — adapter and spacer connectors,

    — bullplugs,

    — valve-removal plugs;

    f) other equipment:

    — actuators,

    — clamp hubs,

    — pressure boundary penetrations,

    — ring gaskets,

    — running and testing tools (see Annex H),

    — wear bushings (see Annex H).

    The nomenclature used in this International Standard for typical equipment is shown in Figures 1 and 2. All parts whose physical dimensions conform to the metric tables incorporated into the body of this International Standard or to the tables in USC units in Annex B are acceptable; see Introduction.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8d1528b3-1272-45f6-9457-7f84c7715f48.htm 01-Oct-10
    ANSI/API SPEC 6A 20TH ED (E1) (E2) (E3) (E4) (E5) (E6) (E7) (E8) (A1) (A2) (A3) Specification for Wellhead and Christmas Tree Equipment; Twentieth Edition; Effective Date: April 1, 2011 1.1 Purpose

    This International Standard specifies requirements and gives recommendations for the performance, dimensional and functional interchangeability, design, materials, testing, inspection, welding, marking, handling, storing, shipment, purchasing, repair and remanufacture of wellhead and Christmas tree equipment for use in the petroleum and natural gas industries.

    This International Standard does not apply to field use, field testing or field repair of wellhead and Christmas tree equipment.

    1.2 Applicability

    This International Standard is applicable to the following specific equipment:

    a) wellhead equipment:

    — casing-head housings,

    — casing-head spools,

    — tubing-head spools

    — cross-over spools,

    — multi-stage head housings and spools;

    b) connectors and fittings:

    — cross-over connectors,

    — tubing-head adapters,

    — top connectors

    — tees and crosses

    — fluid-sampling devices,

    — adapter and spacer spools;

    c) casing and tubing hangers:

    — mandrel hangers

    — slip hangers;

    d) valves and chokes:

    — single valves,

    — multiple valves,

    — actuated valves,

    — valves prepared for actuators,

    — check valves,

    — chokes,

    — surface and underwater safety valves and actuators,

    — back-pressure valves;

    e) loose connectors [flanged, threaded, other end connectors (OEC), and welded]:

    — weld neck connectors,

    — blind connectors,

    — threaded connectors,

    — adapter and spacer connectors,

    — bullplugs,

    — valve-removal plugs;

    f) other equipment:

    — actuators,

    — clamp hubs,

    — pressure boundary penetrations,

    — ring gaskets,

    — running and testing tools (see Annex H),

    — wear bushings (see Annex H).

    The nomenclature used in this International Standard for typical equipment is shown in Figures 1 and 2. All parts whose physical dimensions conform to the metric tables incorporated into the body of this International Standard or to the tables in USC units in Annex B are acceptable; see Introduction.

    1.3 Service conditions

    This International Standard defines service conditions, in terms of pressure, temperature and material class for the well-bore constituents, and operating conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e0c45780-57b5-47e7-a1d4-48df574a7918.htm 01-Mar-13
    ANSI/API SPEC 7-1 1ST ED (A1) Specification for Rotary Drill Stem Elements; First Edition; Effective Date: September 1, 2006; ISO 10424-1:2004 This part of ISO 10424 specifies requirements for the following drill stem

    elements: upper and lower kelly valves; square and hexagonal kellys; drill stem subs; standard steel and non-magnetic drill collars; drilling and coring bits.

    This part of 10424 is not applicable to drill pipe and tool joints, rotary shouldered connection designs, thread gauging practice, or grand master, reference master and working gauges.

    A typical drill stem assembly to which this part of 10424 is applicable is shown in Figure 1.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/1ee4a33b-a239-4a5a-a842-c8e3880c1115.htm 01-Mar-06
    ANSI/API SPEC 7-1 1ST ED (A1) (A2) (A3) (A4) (R 2015) Specification for Rotary Drill Stem Elements; First Edition; Effective Date: September 1, 2006; Reaffirmed, April 2015; ISO 10424-1:2004 This part of ISO 10424 specifies requirements for the following drill stem elements: upper and lower kelly valves; square and hexagonal kellys; drill stem subs; standard steel and non-magnetic drill collars; drilling and coring bits.

    This part of 10424 is not applicable to drill pipe and tool joints, rotary shouldered connection designs, thread gauging practice, or grand master, reference master and working gauges.

    A typical drill stem assembly to which this part of 10424 is applicable is shown in Figure 1.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/12f0dda8-4f6a-4cbe-a713-430d645dfcd0.htm 01-Apr-15
    ANSI/API SPEC 7-1 1ST ED (A1) (A2) (A3) (R 2015) Specification for Rotary Drill Stem Elements; First Edition; Effective Date: September 1, 2006; Reaffirmed, April 2015; ISO 10424-1:2004 This part of ISO 10424 specifies requirements for the following drill stem elements: upper and lower kelly valves; square and hexagonal kellys; drill stem subs; standard steel and non-magnetic drill collars; drilling and coring bits.

    This part of 10424 is not applicable to drill pipe and tool joints, rotary shouldered connection designs, thread gauging practice, or grand master, reference master and working gauges.

    A typical drill stem assembly to which this part of 10424 is applicable is shown in Figure 1.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/8c665658-530e-4554-b582-87b0fcd94a43.htm 01-Apr-15
    ANSI/API SPEC Q1 4TH ED (1992) Specification for Quality Programs; Fourth Edition 1.1 General

    This International Standard specifies requirements for a quality management system where an organization

    a) needs to demonstrate its ability to consistently provide product that meets customer and applicable statutory and regulatory requirements, and

    b) aims to enhance customer satisfaction through the effective application of the system, including processes for continual improvement of the system and the assurance of conformity to customer and applicable statutory and regulatory requirements.

    NOTE 1 In this International Standard the term “product” applies only to

    a) the product intended for, or required by, a customer.

    b) any intended output resulting from the product realization process.

    NOTE 2 Statutory and regulatory requirements can be expressed as legal requirements.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fee1a60a-575a-438b-9ed2-0aced98bb347.htm 01-Jan-92
    ANSI/API TR 5C3 1ST ED (2008) Technical Report on Equations and Calculations for Casing, Tubing, and Line Pipe Used as Casing or Tubing; and Performance Properties Tables for Casing and Tubing; First Edition This Technical Report illustrates the equations and templates necessary to calculate the various pipe properties given in International Standards, including

    — pipe performance properties, such as axial strength, internal pressure resistance and collapse resistance,

    — minimum physical properties,

    — product assembly force (torque),

    — product test pressures,

    — critical product dimensions related to testing criteria,

    — critical dimensions of testing equipment, and

    — critical dimensions of test samples.

    For equations related to performance properties, extensive background information is also provided regarding their development and use.

    Equations presented here are intended for use with pipe manufactured in accordance with ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L, as applicable. These equations and templates may be extended to other pipe with due caution. Pipe cold-worked during production is included in the scope of this Technical Report (e.g. cold rotary straightened pipe). Pipe modified by cold working after production, such as expandable tubulars and coiled tubing, is beyond the scope of this Technical Report.

    Application of performance property equations in this Technical Report to line pipe and other pipe is restricted to their use as casing/tubing in a well or laboratory test, and requires due caution to match the heat-treat process, straightening process, yield strength, etc., with the closest appropriate casing/tubing product. Similar caution should be exercised when using the performance equations for drill pipe.

    This Technical Report and the equations contained herein relate the input pipe manufacturing parameters in ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L to expected pipe performance. The design equations in this Technical Report are not to be understood as a manufacturing warrantee. Manufacturers are typically licensed to produce tubular products in accordance with manufacturing specifications which control the dimensions and physical properties of their product. Design equations, on the other hand, are a reference point for users to characterize tubular performance and begin their own well design or research of pipe input properties.

    This Technical Report is not a design code. It only provides equations and templates for calculating the properties of tubulars intended for use in downhole applications. This Technical Report does not provide any guidance about loads that can be encountered by tubulars or about safety margins needed for acceptable design. Users are responsible for defining appropriate design loads and selecting adequate safety factors to develop safe and efficient designs. The design loads and safety factors will likely be selected based on historical practice, local regulatory requirements, and specific well conditions. All equations and listed values for performance properties in this Technical Report assume a benign environment and material properties conforming to ISO 11960 or API 5CT, ISO 11961 or API 5D and ISO 3183 or API 5L. Other environments may require additional analyses, such as that outlined in Annex D.

    Pipe performance properties under dynamic loads and pipe connection sealing resistance are excluded from the scope of this Technical Report.

    Throughout this Technical Report tensile stresses are positive.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/a2aaf26f-f224-4f1a-8c91-50127724c673.htm 01-Dec-08
    ANSI/API TR 5C3 1ST ED (A1) Technical Report on Equations and Calculations or Casing, Tubing, and Line Pipe Used as Casing or Tubing; and Performance Properties Tables for Casing and Tubing; First Edition; ISO 10400:2007 This Technical Report illustrates the equations and templates necessary to calculate the various pipe properties given in International Standards, including

    — pipe performance properties, such as axial strength, internal pressure resistance and collapse resistance,

    — minimum physical properties,

    — product assembly force (torque),

    — product test pressures,

    — critical product dimensions related to testing criteria,

    — critical dimensions of testing equipment, and

    — critical dimensions of test samples.

    For equations related to performance properties, extensive background information is also provided regarding their development and use.

    Equations presented here are intended for use with pipe manufactured in accordance with ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L, as applicable. These equations and templates may be extended to other pipe with due caution. Pipe cold-worked during production is included in the scope of this Technical Report (e.g. cold rotary straightened pipe). Pipe modified by cold working after production, such as expandable tubulars and coiled tubing, is beyond the scope of this Technical Report.

    Application of performance property equations in this Technical Report to line pipe and other pipe is restricted to their use as casing/tubing in a well or laboratory test, and requires due caution to match the heat-treat process, straightening process, yield strength, etc., with the closest appropriate casing/tubing product. Similar caution should be exercised when using the performance equations for drill pipe.

    This Technical Report and the equations contained herein relate the input pipe manufacturing parameters in ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L to expected pipe performance. The design equations in this Technical Report are not to be understood as a manufacturing warrantee. Manufacturers are typically licensed to produce tubular products in accordance with manufacturing specifications which control the dimensions and physical properties of their product. Design equations, on the other hand, are a reference point for users to characterize tubular performance and begin their own well design or research of pipe input properties.

    This Technical Report is not a design code. It only provides equations and templates for calculating the properties of tubulars intended for use in downhole applications. This Technical Report does not provide any guidance about loads that can be encountered by tubulars or about safety margins needed for acceptable design. Users are responsible for defining appropriate design loads and selecting adequate safety factors to develop safe and efficient designs. The design loads and safety factors will likely be selected based on historical practice, local regulatory requirements, and specific well conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/11bdb4f5-dbcc-428e-a5d5-4f1995acac3d.htm 01-Oct-15
    API 1115 1ST ED (1994) Operation of Solution-Mined Underground Storage Facilities; First Edition This recommended practice provides basic guidance on the operation of solution-mined underground hydrocarbon liquid or liquefied petroleum gas storage facilities. This document is intended for first-time cavern engineers or supervisors, but would also be valuable to those people experienced in cavern operations. This recommended practice is based on the accumulated knowledge and experience of geologists, engineers, and other personnel in the petroleum industry. All aspects of solution-mined underground storage operation, including cavern hydraulics, brine facilities, wellhead and hanging strings, and cavern testing are covered. Users of this guide are reminded that no publication of this type can be complete, nor can any written document be substituted for effective site-specific operating procedures.

    This recommended practice does not apply to caverns used for natural gas storage, waste disposal purposes, caverns which are mechanically mined, depleted petroleum reserve cavities, or other underground storage systems which are not solution-mined.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f96f3300-1054-431c-8c64-54dd4dccfa83.htm 01-Sep-94
    API BUL 11L2 1ST ED (R 1999) Catalog of Analog Computer Dynamometer Cards; First Edition; Reaffirmed, September 1999 In the group of users and manufactures of sucker rod pumping equipment undertook a study in depth of many complex problems associated with this means of lifting fluid from a well. To control and direct the effort, Sucker Rod Pumping Research, Incorporated, a non-profit organization was created. The services of a Midwest Research Institute at Kansas City were retained to perform the work necessary to achieve the objectives the organization.

    As apart of this project, more than110 polished rod dynamometer cards taken with the electronic analog simulator at Midwest Research Institute. These were recognized and presented in catalog from as Summary Report Vol.II of II January 1 – December 31, 1960,M.R.I Project No. 2376-E. Sucker Rod Pumping Research , Incorporated, before its dissolution , released this catalog of cards to the American Petroleum Institute. It was determined by the committee on Standardization of Production Equipment at the Midyear Standardization Conference and reported in Cire PS-1382 dated August, 1969 that the catalog would be published by the API Dallas office for the cost of reproduction

    Nomenclature is that used in API RP 11L: Recommended Practice for Design Calculations for Sucker Rod Pumping Systems. The cards were derived for many combinations of the independent non dimensional parameters Fo / Skr and N / N6. The cards are published for information and reference.

    A discussion of the information presented, including an explanation of the numbers and material on the card sheets, may be found in the following paragraphs. Suggestions for card use are also given. This discussion is included through the courtesy of Mr. M. H. Halderson, Philips Petroleum Company


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/3fd57bc4-8fe3-4c04-bda5-89d14866a4aa.htm 01-Sep-99
    API BUL 16J 1ST ED (1992) Bulletin on Comparison of Marine Drilling Riser Analyses; First Edition a. Recognizing the need for a standard method of analyzing marine drilling risers, the API Committee on the Standardization of Offshore Structures began a program of comparing existing computer programs for such analyses. To make this comparison, a standard set of problems was defined and a Task Group formed by the Committee on Standardization of Offshore Structures obtained computer solutions of this set from various participants. The First Edition of API RP 2J was issued in January 1977. This Edition now under the jurisdiction of the Committee on Standardization of Drilling Well Control Systems and renumbered Bul 16J has added a number of deepwater cases along with some random wave cases. The number of participants has increased from nine to 14. The statistical summaries of these solutions are presented in this bulletin.

    b. The purposes of issuing these results are: (1) to show the degree of agreement among a representative group of riser analysis computer programs. and (2) to present data which can be used to help validate other such programs.

    c. In cases where the results of a participant differed significantly (some 25% or more) from the consistently clustered results of the majority of the participants, results were omitted. Numerous attempts were made by the committee members to assist participants in correcting input errors, problem definitions, and other likely sources of disagreement. The omissions were handled on a problem by problem basis, i.e., the number of solutions used to compile the results for each problem varies. The number of solutions included for each individual problem is indicated throughout the tables and figures in parentheses following the problem designation.

    d. None of these results have been directly validated by measurements on equivalent real risers, although some of the programs have been partially validated in other applications. Comparisons such as those described here are not intended to replace or lessen the need for such validation.

    e. American Petroleum Institute (API) Bulletins are published to provide information for which there is a broad industry need but which does not constitute either Specifications or Recommended Practices.

    f. Any Bulletin may be used by anyone desiring to do so, and a diligent effort has been made by API to assure the accuracy and reliability of the data contained herein. However, the Institute makes no representation, warranty or guarantee in connection with the publication of any bulletin and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use, for any violation of any federal, state, or municipal regulation with which an API recommendation may conflict, or for the infringement of any patent resulting from the use of this publication.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/69156d6c-f7b9-46a0-8d30-2d1f16135210.htm 01-Aug-92
    API BUL 2513 (R 1973) Evaporation Loss in the Petroleum Industry-Causes and Control; February 1959; Reaffirmed, 1973 The petroleum industry has been concerned about evaporation from crude oil and its products for many years. In 1953, the American Petroleum Institute formed the Committee on Evaporation Loss Measurement to study evaporation loss and ways to control it. This bulletin, prepared by that committee, will aid superintendents, managers, and engineers in carrying out an effective loss-control program. When loss problems are adequately understood loss will be minimized.

    Common sources of evaporation loss are: a, storage tanks—from breathing, emptying, filling, or boiling; b, production—from gas-oil separation and emulsion treating; c, refining—from treating in freely vented vessels, leaky pressure systems, sewers, ponds, and open separators; and d, transportation—from loading, transit, and unloading of cargo vessels and from pipelines. Also under certain conditions, such as inaccurate measurement of stock movements, a loss appears to have occured when actually there is none.

    The rate of evaporation loss depends upon several factors. True vapor pressure is the force causing vaporization and, generally, loss is considered to be more or less directly proportional to it. Atmospheric and solar-heat changes cause the tank vapor space to breathe, and vapor-space volume affects the amount of breathing. Loss rate probably is less than directly proportional to vapor volume and daily atmospheric-temperature change.

    For storage of petroleum and its products, the industry can choose from four basic types of tanks, fixed-roof, floating-roof, variable-vapor-space, and pressure. Each design meets specific storage needs. Selecting the most economical tank often requires careful study of the different types. For each tank, effective loss control depends upon accessories such as breather valves and automatic gages. To maintain effective control, the tank and accessories must be kept gastight. Choice of paint color is also an important factor.

    The operating procedures used in production, refining, transportation, and marketing are all important in controlling evaporation loss. Prevention of leaks from glands, valves, and fittings should be common to all branches of the industry. In production, control of temperature in the gas-oil separators and in the emulsion-treating equipment is necessary. In refining, operation of treating plants, sewers, ponds, and open separators require special consideration. In transportation, careful scrutiny of the methods for loading and unloading is essential.

    Control of evaporation loss requires that continued attention be given to operating procedures and maintenance of equipment. Conservation equipment sometimes becomes less effective with age and an evaluation frequently reveals that modernization would pay. These factors demonstrate the need for organized programs for loss control. Only in this way will the necessary concerted attention be given this important subject.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/1e4a6744-ecd6-4a24-812b-37ce4899be7d.htm 01-Feb-59
    API BUL 2HINS 1ST ED (2009) Guidance for Post-hurricane Structural Inspection of Offshore Structures; First Edition This document is applicable to permanent fixed and floating structures in the Gulf of Mexico. In this document, inspection refers to structural inspections only and does not include inspections of production equipment, process piping, electrical and instrumentation or other systems and components of the platform, unless noted otherwise.

    Fixed structures include steel jacket or template platforms, towers and compliant towers, caissons, minimum non-jacket and special structures that are fixed to the seafloor. Design of these structures generally follows API 2A-WSD guidelines.

    Floating structures include tension leg platforms (TLPs), spars, deep draft caisson vessels, semi-submersibles and any other type of floating or tethered structures. Design of these structures generally follows API 2T, API 2FPS, API 2SK, API 2RD and API 2I guidelines.

    Post-hurricane structural inspections are not as comprehensive as, or supplant the need for, regular in-service inspections as may be detailed in the structure's in-service inspection plan (ISIP).

    This document describes post-hurricane structural inspection of structures designed in accordance with the following API documents:

    — API 2A-LRFD,

    — API 2A-WSD

    — API 2FPS,

    ,— API 2I,

    — API 2RD,

    — API 2SK,

    — API 2T,

    — API 2TD.

    These structures may also be designed and operated in accordance with regulatory and classification society guidelines and these should be applied as required.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c1f32f88-12ce-46cf-bb44-687e6bb72945.htm 01-May-09
    API BUL 2S 2ND ED (R 2001) Design of Windlass Wildcats for Floating Offshore Structures; Second Edition; Reaffirmed, January 2001 1.1This publication covers cast steel wildcats as used in windlass to haul in the pay-out anchor. An associated chain stopper is used to secure the chain while the vessel is anchored or the anchor is housed.

    1.2Wildcats are of the five-whelp type for use with stud link anchor chain conforming to the classification society grades 1, 2 and 3, ORQ and Grade 4 chain. Wildcat dimensions are provided for chains in integral Vs-in. (3-mm) steps, ranging in size from 2 in. to 4 in. (51 mm to 102 mm). Wildcat dimensions for chain in intermediate Vi6 in. (1.5 mm) steps are not provided, but wildcats in these sizes are permitted within the scope of this publication. Wildcats designed in millimeters must be compatible with chain manufactured in millimeters. Wildcats designed in inches must be compatible with chain manufactured in inches.

    CAUTION: Compatibility of wildcat and applicable chain standard is necessary.

    1.3Wildcats are configured to pass detachable links oriented parallel or perpendicular to the wildcat shaft centerline.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/169ed831-dee6-4260-b643-e3550b11e91a.htm 01-Jan-01
    API BUL 2TD 1ST ED (2006) Guidelines for Tie-downs on Offshore Production Facilities for Hurricane Season; First Edition This document addresses situations where failure of a drilling or workover rig would result in significant damage to the platform or adjacent infrastructure. Generally, this would include any facility designated as having a high or medium consequence of failure as defined by API RP2A. In other situations, a risk-based operational decision process should be followed. Situations that might allow deviation from the recommendations below include drilling operations in the non-hurricane season or the use of light-weight workover masts on shallow water platforms.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3d7d1cda-6f8d-463c-b20c-6c8a243ad9f5.htm 01-Jun-06
    API BUL 2U 3RD ED (2004) Bulletin on Stability Design of Cylindrical Shells; Third Edition 1.1.1 This Bulletin provides stability criteria for determining the structural adequacy against buckling of large diameter circular cylindrical members when subjected to axial load, bending, shear and external pressure acting independently or in combination. The cylinders may be unstiffened, longitudinally stiffened, ring stiffened or stiffened with both longitudinal and ring stiffeners. Research and development work leading to the preparation and issue of all three editions of this Bulletin is documented in References 1 through 16 and the Commentary.

    1.1.2 The buckling capacities of the cylinders are based on linear bifurcation (classical) analyses reduced by capacity reduction factors which account for the effects of imperfections and nonlinearity in geometry and boundary conditions and by plasticity reduction factors which account for nonlinearity in material properties. The reduction factors were determined from tests conducted on fabricated steel cylinders. The plasticity reduction factors include the effects of residual stresses resulting from the fabrication process.

    1.1.3 Fabricated cylinders are produced by butt-welding together cold or hot formed plate materials. Long fabricated cylinders are generally made by butt-welding together a series of short sections, commonly referred to as cans, with the longitudinal welds rotated between the cans. Long fabricated cylinders generally have D/t ratios less than 300 and are covered by AP RP 2A.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0e77aecc-c95a-4891-bf2b-2786138f7b19.htm 01-Jun-04
    API BUL 2V 3RD ED (2004) Design of Flat Plate Structures; Third Edition 2.1.1 Bulletin 2V provides guidance for the design of steel flat plate structures. These often constitute main components of offshore structures. When applied to Tension Leg Platforms (TLPs) this Bulletin should be viewed as a complement to API RP 2T. The Bulletin combines good practice considerations with specific design guidelines and information on structural behavior. As such it provides a basis for taking a "design by analysis" approach to structural design of offshore structures.

    2.1.2 Flat plate structures include thin plates, stiffened panels and deep plate girders, and they can constitute the main component of decks, bulkheads, web frames and flats. The external shell of pontoons or columns can also be made of flat stiffened panels if their cross section is, for example, square or rectangular, rather than circular.

    2.1.3 Bulletin 2V is not a comprehensive document, and users have to recognize the need to exercise engineering judgment in actual applications, particularly in the areas that are not specifically covered.

    2.1.4 Plates are discussed in Section 3, stiffeners in Section 4, stiffened panels in Section 5, and deep plate girders in Section 6. Limit states are given for each relevant load and load combination, and design requirements are also defined. Figure 2.1-1 summarizes the structural components and the limit states covered in Bulletin 2V.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0747ff62-e91b-4a02-ab04-6acfba8f8f62.htm 01-Jun-04
    API BUL 4719 1ST ED (2017) Industry Guidelines on Requesting Regulatory Concurrence for Subsea Dispersant Use; First Edition The purpose of this document is to provide guidelines, forms, and checklists recommended for use by industry. The API guidelines describe the RRT concurrence request process, proposed information submission recommendations that are specific to subsea dispersant injection, and the use of Spill Impact Mitigation Analysis (SIMA) and other forms of tradeoff analyses as decision support tools. Also included are practical flowcharts and checklists specific to Incident Management Team (IMT) positions that are integral to subsea dispersant use, and guidance on the preparation of subsea dispersant operations and monitoring plans. This document provides operational guidelines intended for actual events or exercises and provides a basis for engagement from a range of relevant stakeholders.

    This document provides guidelines for the regulatory approval in accordance with Subpart J for the use of subsea dispersants in the United States with several U.S. references since subsea dispersants were first used for one incident in the United States. The lessons learned captured by numerous companies, in addition to input from members of IPIECA and IOGP, serve as a baseline for initial guidance to share with other countries and organizations to assist in developing their own guidelines.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/aad7c9a0-d9a8-434a-be7d-98195b82e49c.htm 01-Jun-17
    API BUL 5C2 10TH ED (1968) Bulletin on Performance Properties of Casing and Tubing; Tenth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d.Other specifications, bulletins, and recommended practices under the jurisdiction of the committee on Standardization of Tubular Goods include the following:

    Std %A: Specification for Casing, Tubing, and Drill Pipe.

    Covers seamless steel drill pope and seamless and welded steel casing and tubing in various grades. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std 5AC: Specification for Grade C-75 Casing and Tubing (Tentative)

    Covers process of manufacture, chemical and physical requirements, methods of test, and dimensions for Grade C-75 casing and tubing.

    Std 5AX Specification for High-Strength Casing and Tubing.

    Covers high-strength seamless casing and tubing. Processes of manufacture, chemical and physical requirements, methods, of test, and dimensions are included.

    Std. 5B: Specification for threading, Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads.

    Covers dimensional requirements on threads and thread gages, stipulations on gaging practice, gage specification and certification, as well as instruments and methods for the inspection of threads of round-thread casing and tubing, butters thread casing, extreme-line casing, and line pipe.

    Std 5L Specification for Line Pipe.

    Covers seamless and welded steel line pipe in various grades. It includes standard-weight threaded line pipe; and standard-weight, regular weight, special, extra-strong, and double extra-strong, plain-end line pipe. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std. 5LA: Specification for Schedule 5 Aluminum Alloy Line Pipe (Tentative).

    Covers dimensional and chemical requirements for plain-end extruded and/ or drawn Schedule 5 aluminum alloy line pipe for use in the petroleum industry.

    Std 5LS: Specification for Spiral-Weld Line Pipe.

    Covers requirements for various grades of spiral weld line pipe. Processes of manufacture, chemical and physical requirements, methods of test, and dimension are included.

    Std 5LX: Specification for High-Test Line Pipe.

    Covers various grades if seamless and welded steel line pipe having greater tensile and bursting strengths and subject to more rigorous testing than for pipe manufactured under API Std 5L. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std 5A2: Bulletin on Thread Compounds.

    Provides material requirements and performance tests for two grades of thread compound use on oil-field tubular goods.

    RP 5C1: Recommended Practice for Care and Use of Casing, Tubing, and Drill Pipe.

    Covers use, transportation, storage, handling, and reconditioning of casing, tubing, and drill pipe.

    RP5L1: Recommended Practice for Railroad Transportation of Line Pipe.

    Provides a recommended procedure for loading large diameter line pipe (24 to 42 in. OD incl.) on railroad cars.

    RP 5L2: Recommended Practice for Internal Coating of Line Pipe for Gas Transmissions Service.

    Covers Coating materials, application practices and section of internal coating on new pipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b0c6b6a9-63d3-426e-88ca-6c179f6b31d2.htm 01-Apr-68
    API BUL 5C2 11TH ED (1969) Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe; Eleventh Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9107b039-bc7a-48ef-94f3-17bb55ec741d.htm 01-Apr-69
    API BUL 5C2 12TH ED (1970) Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe; Twelfth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d6da6091-3b64-4f14-9745-b3d5c256c9f1.htm 01-Apr-70
    API BUL 5C2 13TH ED (1971) Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe; Thirteenth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d. A standard method of collapse testing was adopted by API at the 1970 Standardization Conference. A description of the specimen, the test apparatus, and the procedure is given in Appendix A.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6752089e-dd0e-4257-a341-9f7001826453.htm 01-Apr-71
    API BUL 5C2 14TH ED (1972) Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe; Fourteenth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d. Formulas and procedures for calculating the values herein are given in but 5C3


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a4d79a08-4797-410a-b333-2f42ab4009b2.htm 01-Apr-72
    API BUL 5C2 15TH ED (1974) Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe; Fifteenth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d. Formulas and procedures for calculating the values herein are given in but 5C3


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6bc93cf6-6bbc-47b9-80b4-94b76d10a4c2.htm 01-Jan-74
    API BUL 5C2 16TH ED (1975) Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe; Sixteenth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d. Formulas and procedures for calculating the values herein are given in but 5C3


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/75a7e74e-7ccf-4467-8f74-087417a72dcc.htm 01-Mar-75
    API BUL 5C2 17TH ED (1980) Bulletin on Perfromance Properties of Casing, Tubing, and Drill Pipe; Sevententh Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d. Formulas and procedures for calculating the values herein are given in but 5C3

    e. This bulletin may be used by any desiring to do so and every effort has been made by the Institute to assure the accuracy and reliability of the data contained. However, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use, for any violation of any federal, state, or municipal regulation with which it may conflict, or for the infringement of nay patent resulting from the use of this publication.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/1b9f7cca-b50b-48d0-896a-948c6daff400.htm 01-Mar-80
    API BUL 5C2 18TH ED (1982) Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe; Eighteenth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d. Formulas and procedures for calculating the values herein are given in but 5C3

    e. This bulletin may be used by any desiring to do so and every effort has been made by the Institute to assure the accuracy and reliability of the data contained. However, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use, for any violation of any federal, state, or municipal regulation with which it may conflict, or for the infringement of nay patent resulting from the use of this publication.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0d1978a9-c96f-4cac-beb4-a584f816c806.htm 01-Mar-82
    API BUL 5C2 19TH ED (1984) Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe; Nineteenth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing, tubing, and drill pipe strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d. Formulas and procedures for calculating the values herein are given in but 5C3

    e. This bulletin may be used by any desiring to do so and every effort has been made by the Institute to assure the accuracy and reliability of the data contained. However, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use, for any violation of any federal, state, or municipal regulation with which it may conflict, or for the infringement of nay patent resulting from the use of this publication.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/cdc7880d-3735-42a0-8ba3-604ab572b95a.htm 01-Oct-84
    API BUL 5C2 20TH ED (1987) Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe; Twentieth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing, tubing, and drill pipe strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d. Formulas and procedures for calculating the values herein are given in but 5C3

    e. This bulletin may be used by any desiring to do so and every effort has been made by the Institute to assure the accuracy and reliability of the data contained. However, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use, for any violation of any federal, state, or municipal regulation with which it may conflict, or for the infringement of nay patent resulting from the use of this publication.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/1f12e6c6-ee90-4f0a-860d-53c694fadd34.htm 01-May-87
    API BUL 5C2 4TH ED (1948) Bulletin on Performance properties of Casing and Tubing; Fourth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Oil County Tubular Goods.

    b. This bulletin gives minimum performance properties of casing and tubing. The values shown herein for casing are final, and are based mainly upon tests, as explained further in Section I; the values for tubing are tentative, and are calculated, as explained further in Section II.

    c. See Appendix A for historical data and additional information on derivation of values on casing.

    See API RP 5C1 for recommended Practice on Transportation, Storage, Handling, and Reconditioning of Casting, Drill Pipe, and Tubing.

    e.Other specifications, bulletins, and recommended practices under the jurisdiction of this committee are:

    Std 5A: Specification for Casing, Tubing, and Drill Pipe.

    Covers seamless steel drill pope and seamless and welded steel casing, open hearth iron and wrought iron casing and tubing in various grades. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included, also thread and gage dimensions, gaging practice, and requirements on couplings and thread protectors.

    Std. 5B: Specification for Inspection of threats.

    Covers methods of inspecting internal and external pipe threads and description of instruments for measuring thread elements.

    Std 5L Specification for Line Pipe.

    Covers seamless and welded steel, seamless and welded open hearth iron, and welded wrought iron line pipe in various grades. It includes threaded standard-weight threaded line pipe; and standard-weight, regular weight, special, extra-strong, and double extra-strong, plain-end line pipe. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are include, also thread and gaging dimensions, gaging practice, requirements on couplings and thread protectors.

    Std 5LX: Specification for High-Test Line Pipe.

    Covers various grades of seamless and welded steel line pipe having greater tensile and bursting strengths and subject to more rigorous testing than for pipe manufactured under API Std 5L. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    5A1: Bulletin on High-Strength Casing Joints.

    Covers minimum performance properties for proposed API high-strength casing joints.


    RP 5C1: Recommended Practice for Care and Use of Casing, Tubing, and Drill Pipe. Covers use, transportation, storage, handling, and reconditioning of casing, drill pipe, and tubing.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0b5ce341-e17a-43cd-8163-f3570d353818.htm 01-Aug-48
    API BUL 5C2 5TH ED (1952) Bulletin on Performance Properties of Casing and Tubing; Fifth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Oil County Tubular Goods.

    b. This bulletin gives minimum performance properties of casing and tubing. The values shown for casing are based mainly on tests, as explained further in Sect. I. The properties for tubing are calculated values, as confirmed by actual tests.

    c. See Appendix A for historical data and additional information on derivation of values on casing.

    d.Other specifications, bulletins, and recommended practices under the jurisdiction of this committee are:

    Std 5A: Specification for Casing, Tubing, and Drill Pipe.

    Covers seamless steel drill pope and seamless and welded steel casing, open heath iron and wrought iron casing and tubing in various grades. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included, also thread and gage dimensions, gaging practice, and requirements on couplings and thread protectors.

    Std. 5B: Specification for Inspection of threads .

    Covers methods of inspecting internal and external pipe threats and description of instruments for measuring thread elements.

    Std 5L Specification for Line Pipe.

    Covers seamless and welded steel, seamless and welded open hearth iron, and welded wrought iron line pipe in various grades. It includes standard-weight threaded line pipe; and standard-weight, regular weight, special, extra-strong, and double extra-strong, plain-end line pipe. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions, gaging practice, and requirements on couplings and thread protectors.

    Std 5LX: Specification for High-Test Line Pipe.

    Covers various grades of seamless and welded steel line pipe having greater tensile and bursting strengths and subject to more rigorous testing than for pipe manufactured under API Std 5L. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    5A1: Bulletin on High-Strength Casing Joints.

    Covers minimum performance properties for proposed API high-strength casing joints.

    RP 5C1: Recommended Practice for Care and Use of Casing, Tubing, and Drill Pipe.

    Covers use, transportation, storage, handling, and reconditioning of casing, drill pipe, and tubing.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/2d8afcdf-fff1-4a5a-909c-b3e863954c17.htm 01-Jan-52
    API BUL 5C2 6TH ED (1956) Bulletin on Performance Properties of Casing and Tubing; Sixth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of casing and tubing strings may be based. The collapse pressures and joint strengths are based on actual values determined by tests from which equations were derived for calculating average properties for the various grades, sizes, and weights. For the purposed of obtaining minimum values, these equations for average values were modified by the introduction of a factor of 0.75 for collapse resistance and .80 for joint strength. The internal yield pressures given herein are calculated values, calculated by the Barlow equation, into which a factor of 0.875 was introduced to compensate for 12.5 per cent under tolerance on wall thickness as provided in API Std 5A.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A.

    d.Other specifications, bulletins, and recommended practices under the jurisdiction of this committee are:

    Std 5A: Specification for Casing, Tubing, and Drill Pipe.

    Covers seamless steel drill pope and seamless and welded steel casing and tubing in various grades. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std. 5B: Specification for threading, Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads.

    Covers dimensional requirements on threads and thread gages, stipulations on gaging practice, gage specification and certification, as well as instruments and methods for the inspection of threads of round-thread casing and tubing, butters thread casing, extreme-line casing, and line pipe.

    Std 5L Specification for Line Pipe.

    Covers seamless and welded steel line pipe in various grades. It includes standard-weight threaded line pipe; and standard-weight, regular weight, special, extra-strong, and double extra-strong, plain-end line pipe. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std 5LX: Specification for High-Test Line Pipe.

    Covers various grades if seamless and welded steel line pipe having greater tensile and bursting strengths and subject to more rigorous testing than for pipe manufactured under API Std 5L. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    5A: Bulletin on Obsolete Sharp Threads for Casing and Tubing.

    Covers dimensional data for casing and tubing sharp threads, now superseded by round-form threads.

    5A1: Bulletin on High-Strength Casing Joints.

    Covers minimum performance properties for proposed API high-strength casing joints.

    Std 5A2: Bulletin on Thread Compounds. Covers the formulation, process of manufacture, and labeling of thread compound for high pressure oil-field service, as developed at the Mellon Institute under API sponsorship RP 5C1: Recommended Practice for Care and Use of Casing, Tubing, and Drill Pipe. Covers material requirements and performance tests for two grades of thread compound for use an oil-field tubular goods.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0b0df5fa-d8b6-4616-b4a0-13239d846b1e.htm 01-Jul-56
    API BUL 5C2 7TH ED (1957) Bulletin on Performance Properties of Casing and Tubing; Seventh Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of casing and tubing strings may be based. The collapse pressures and joint strengths are based on actual values determined by tests from which equations were derived for calculating average properties for the various grades, sizes, and weights. For the purposed of obtaining minimum values, these equations for average values were modified by the introduction of a factor of 0.75 for collapse resistance and .80 for joint strength. The internal yield pressures given herein are calculated values, calculated by the Barlow equation, into which a factor of 0.875 was introduced to compensate for 12.5 per cent under tolerance on wall thickness as provided in API Std 5A.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A.

    d.Other specifications, bulletins, and recommended practices under the jurisdiction of this committee are:

    Std 5A: Specification for Casing, Tubing, and Drill Pipe.

    Covers seamless steel drill pope and seamless and welded steel casing and tubing in various grades. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std. 5B: Specification for threading, Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads.

    Covers dimensional requirements on threads and thread gages, stipulations on gaging practice, gage specification and certification, as well as instruments and methods for the inspection of threads of round-thread casing and tubing, butters thread casing, extreme-line casing, and line pipe.

    Std 5L Specification for Line Pipe.

    Covers seamless and welded steel line pipe in various grades. It includes standard-weight threaded line pipe; and standard-weight, regular weight, special, extra-strong, and double extra-strong, plain-end line pipe. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std 5LX: Specification for High-Test Line Pipe.

    Covers various grades if seamless and welded steel line pipe having greater tensile and bursting strengths and subject to more rigorous testing than for pipe manufactured under API Std 5L. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    5A: Bulletin on Obsolete Sharp Threads for Casing and Tubing.

    Covers dimensional data for casing and tubing sharp threads, now superseded by round-form threads.

    5A1: Bulletin on High-Strength Casing Joints.

    Covers minimum performance properties for proposed API high-strength casing joints.

    Std 5A2: Bulletin on Thread Compounds.

    Provides material requirements and performance tests for two grades of thread compound use on oil-field tubular goods.

    RP 5C1: Recommended Practice for Care and Use of Casing, Tubing, and Drill Pipe.

    Covers material requirements and performance tests for two grades of thread compound for use an oil-field tubular goods.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/92cd72f4-40ea-4b0d-a9ca-9a515889cc42.htm 01-May-57
    API BUL 5C2 8TH ED (1964) Bulletin on Performance Properties of Casing and Tubing; Eighth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d.Other specifications, bulletins, and recommended practices under the jurisdiction of the committee on Standardization of Tubular Goods include the following:

    Std 5A: Specification for Casing, Tubing, and Drill Pipe.

    Covers seamless steel drill pope and seamless and welded steel casing and tubing in various grades. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std 5AC: Specification for Grade C-75 Casing and Tubing (Tentative)

    Covers process of manufacture, chemical and physical requirements, methods of test, and dimensions for Grade C-75 casing and tubing.

    Std 5AX Specification for High-Strength Casing and Tubing.

    Covers high-strength seamless casing and tubing. Processes of manufacture, chemical and physical requirements, methods, of test, and dimensions are included.

    Std. 5B: Specification for threading, Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads.

    Covers dimensional requirements on threads and thread gages, stipulations on gaging practice, gage specification and certification, as well as instruments and methods for the inspection of threads of round-thread casing and tubing, butters thread casing, extreme-line casing, and line pipe.

    Std 5L Specification for Line Pipe.

    Covers seamless and welded steel line pipe in various grades. It includes standard-weight threaded line pipe; and standard-weight, regular weight, special, extra-strong, and double extra-strong, plain-end line pipe. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std. 5LA: Specification for Schedule 5 Aluminum Alloy Line Pipe (Tentative).

    Covers dimensional and chemical requirements for plain-end extruded and/ or drawn Schedule 5 aluminum alloy line pipe for use in the petroleum industry.

    Std 5LX: Specification for High-Test Line Pipe.

    Covers various grades if seamless and welded steel line pipe having greater tensile and bursting strengths and subject to more rigorous testing than for pipe manufactured under API Std 5L. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std 5A2: Bulletin on Thread Compounds.

    Provides material requirements and performance tests for two grades of thread compound use on oil-field tubular goods.

    RP 5C1: Recommended Practice for Care and Use of Casing, Tubing, and Drill Pipe.

    Covers material requirements and performance tests for two grades of thread compound for use an oil-field tubular goods.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a9eb0e8f-67e2-4e1f-bf68-045de71bd433.htm 01-Mar-64
    API BUL 5C2 9TH ED (1966) Bulletin on Performance Properties of Casing and Tubing; Ninth Edition a. This bulletin is under the jurisdiction of the Committee on standardization of Tubular Goods.

    b. This bulletin is not intended as a design manual. Its purpose is to provide minimum performance properties on which the design of he casing and tubing strings may be based.

    c. The performance properties as given herein cover the grades, sizes, and weights of casing and tubing as given in API Stds 5A, 5AC, and 5AX.

    d.Other specifications, bulletins, and recommended practices under the jurisdiction of the committee on Standardization of Tubular Goods include the following:

    Std 5A: Specification for Casing, Tubing, and Drill Pipe.

    Covers seamless steel drill pope and seamless and welded steel casing and tubing in various grades. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std 5AC: Specification for Grade C-75 Casing and Tubing (Tentative)

    Covers process of manufacture, chemical and physical requirements, methods of test, and dimensions for Grade C-75 casing and tubing.

    Std 5AX Specification for High-Strength Casing and Tubing.

    Covers high-strength seamless casing and tubing. Processes of manufacture, chemical and physical requirements, methods, of test, and dimensions are included.

    Std. 5B: Specification for threading, Gaging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads.

    Covers dimensional requirements on threads and thread gages, stipulations on gaging practice, gage specification and certification, as well as instruments and methods for the inspection of threads of round-thread casing and tubing, butters thread casing, extreme-line casing, and line pipe.

    Std 5L Specification for Line Pipe.

    Covers seamless and welded steel line pipe in various grades. It includes standard-weight threaded line pipe; and standard-weight, regular weight, special, extra-strong, and double extra-strong, plain-end line pipe. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std. 5LA: Specification for Schedule 5 Aluminum Alloy Line Pipe (Tentative).

    Covers dimensional and chemical requirements for plain-end extruded and/ or drawn Schedule 5 aluminum alloy line pipe for use in the petroleum industry.

    Std 5LS: Specification for Spiral-Weld Line Pipe.

    Covers requirements for various grades of spiral weld line pipe. Processes of manufacture, chemical and physical requirements, methods of test, and dimension are included.

    Std 5LX: Specification for High-Test Line Pipe.

    Covers various grades if seamless and welded steel line pipe having greater tensile and bursting strengths and subject to more rigorous testing than for pipe manufactured under API Std 5L. Processes of manufacture, chemical and physical requirements, methods of test, and dimensions are included.

    Std 5A2: Bulletin on Thread Compounds.

    Covers the formulation, process of manufacture. and labeling of thread compounds for high pressure oil-field service.

    RP 5C1: Recommended Practice for Care and Use of Casing, Tubing, and Drill Pipe.

    Covers material requirements and performance tests for two grades of thread compound for use an oil-field tubular goods.

    RP5L1: Recommended Practice for Railroad Transportation of Line Pipe.

    Provides a recommended procedure for loading large diameter line pipe (24 to 42 in. OD incl.) on railroad cars.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d70578c4-ccfc-4d56-bbe7-e6804896e413.htm 01-Mar-66
    API BUL 5C3 1ST ED (1971) Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties; First Edition a. This bulletin is under the jurisdiction of the Committee on Standardization of Tubular Goods.

    b.The purpose of this bulletin is to show the formulas used in the calculation of the various pipe properties given in API standards, including background information regarding their development and use.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/4234254b-98bf-4ed1-927f-21f9b96be704.htm 01-Dec-71
    API BUL 5C3 2ND ED (1974) Bulletin on Formulas and Calculations for Casinf, Tubing, Drill Pipe, and Line Pipe Properties; Second Edition a. This bulletin is under the jurisdiction of the Committee on Standardization of Tubular Goods.

    b.The purpose of this bulletin is to show the formulas used in the calculation of the various pipe properties given in API standards, including background information regarding their development and use.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8c42257f-9e3c-4b59-adb9-286bc494e7f9.htm 01-Nov-74
    API BUL 5C3 3RD ED (1980) Bulletin on Formulas and Calculations for Casin, Tubing, Drill Pipe, and Line Pipe Properties; Third Edition a. This bulletin is under the jurisdiction of the Committee on Standardization of Tubular Goods.

    b.The purpose of this bulletin is to show the formulas used in the calculation of the various pipe properties given in API standards, including background information regarding their development and use.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6a6437ca-5b36-443a-8bd6-61f410bded4b.htm 01-Mar-80
    API BUL 5C3 4TH ED (1985) Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Propertires; Fourth Edition a. This bulletin is under the jurisdiction of the Committee on Standardization of Tubular Goods.

    b.The purpose of this bulletin is to show the formulas used in the calculation of the various pipe properties given in API standards, including background information regarding their development and use.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/4131a141-f960-4fc4-ae1d-bb98a7d8ed9e.htm 01-Feb-85
    API BUL 5C3 5TH ED (1989) Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe and Line Pipe Properties; Fifth Edition a. This bulletin is under the jurisdiction of the Committee on Standardization of Tubular Goods.

    b.The purpose of this bulletin is to show the formulas used in the calculation of the various pipe properties given in API standards, including background information regarding their development and use.

    c. American Petroleum Institute (API) Bulletins are published to provide information for which there is a broad industry need but which does not constitute either Specifications or Recommended Practices

    d. Any Bulletin may be used by anyone desiring to do so, and a diligent effort has been made by API to assure the accuracy and reliability of the data contained herein. However, the Institute makes no representation, warranty or guarantee in connection with the publication of any Bulletin and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use, for any violation of any patent resulting from the use of this publication.

    e. This standard (supplement) shall become effective on the date printed on the cover but may be used voluntarily from the date of distribution.

    Attention Users: Portions of this publication have been changed from the previous edition. The locations of changed have been marked with a bar in the margin, as shown to the left of this paragraph. In some cases the changes are significant, while in other cases the changed reflect minor editorial adjustments. The bar notions in the margins are provided as an aid to users as to those parts of this publication that have been changed from the previous edition, but API makes no warranty as ti the accuracy of such bar notations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/31251a35-ad39-4015-881a-02655426a379.htm 01-Jul-89
    API BUL 5C3 6TH ED (1994) Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties; Sixth Edition The Purpose of this bulletin is to show the formulas used in the calculation of the various pipe properties given in API standards, including background information regarding their development and use. This bulletin is under the jurisdiction of the committee on Standardization of Tubular Goods.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3ed64f72-6071-4597-b597-ab3480407466.htm 01-Oct-94
    API BUL 5T1 11TH ED (2017) Bulletin on Imperfection and Defect Terminology; Eleventh Edition This document provides terms, definitions, and example figures of imperfections and defects that occur in manufacturing steel tubulars. The words imperfection and defect refer to metallurgical and other features of steel tubular products that may or may not affect the performance of the products. Inspection requirements and acceptance criteria are not defined in this document and are found instead in the respective product specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b03c86c3-5c69-4002-a95a-d533495346bc.htm 01-Oct-17
    API BUL 6J 1ST ED (1992) Bulletin on Testing of Oilfield Elastomers - A Tutorial; First Edition This document is a tutorial for the evaluation of elastomer test samples or actual elastomeric seal members intended for use in the oil and gas industry. In earlier times, most of the oil and gas production was from sweet, low pressure wells and oilfield equipment manufacturers could supply low durometer nitrile rubber for seal members and the customers could depend on the seal with reliability. With time, these oil reserves have been depleted and the search for oil and gas has led to the development of deep, high pressure reservoirs and/or sour (H2S), corrosive oil resources. In a prospective application, the customer and the oilfield equipment manufacturer may not really be sure of the performance of the seal materials and members in the equipment. Many tests exist which evaluate the performance of a seal material or member. It is the intent of this document to review testing criteria, environments, evaluation procedures, guidelines for comparisons, and effects of other considerations on the evaluation of elastomeric seal materials and members.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/e481821e-af5f-41dc-a44d-4d21ed6dfa94.htm 01-Feb-92
    API BUL 91 1ST ED (2007) Planning and Conducting Surface Preparation and Coating Operations for Oil and Natural Gas Drilling and Production Facilities in a Marine Environment; First Edition Worldwide, marine exploration, production, development and decommissioning operations are conducted from a variety of structures (installations, as defined herein). These installations must be inspected periodically and maintained in order to assure structural integrity and minimize pollution risks. Maintenance of an offshore structure, regardless of its classification, necessarily includes blasting and coating activities. The purpose of this publication is to establish practices and procedures that should be followed to minimize the discharge of spent blast abrasive, and paint overspray to the surrounding waters during these activities, to meet the spirit of MARPOL Annex V. Additionally, any maintenance waste which is captured must be properly packaged and shipped to shore for disposal. This publication also addresses procedures to contain and capture maintenance waste, including, but not limited to, spent blast abrasive and associated materials, during such maintenance activities on marine structures. The safety of personnel is the most important consideration for all work activities. Consequently, any blasting and coating work conducted shall consider the safety of personnel as paramount. Other types of discharges that may be permitted by various regulatory authorities, are outside the scope of this document. These would include (1) discharges in compliance with a relevant governmental permit (e.g., the applicable provisions of the U.S. Clean Water Act or the applicable sections of European Community [EC] Dangerous Substances Directives), (2) discharges resulting from circumstances identified and reviewed and made part of the public record with respect to a permit issued or modified and subject to a condition in such permit, and (3) continuous or anticipated intermittent discharges from a point source, identified in a permit or permit application which are caused by events occurring within the scope of relevant operating or treatment systems.

    Additionally, containment issues for operations below the water line are outside the scope of this document.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/db1e1a20-4ef7-403c-99d9-b2f1546f94b1.htm 01-Jun-07
    API BUL 92L 1ST ED (2015) Drilling Ahead Safely with Lost Circulation in the Gulf of Mexico; First Edition This bulletin identifies items that should be considered to safely address lost circulation challenges when the equivalent circulating density (ECD) exceeds the fracture gradient. It addresses drilling margins and drilling ahead with mud losses, which are not addressed in API 65-2. It provides guidance when lost circulation is experienced with either surface or subsea stack operations (excluding diverter operations). These practices may apply to other Outer Continental Shelf (OCS) environments such as offshore California and Florida.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e98fc2f1-b84e-4daf-a41d-adbb3ad1590c.htm 01-Aug-15
    API BUL 97 1ST ED (2013) Well Construction Interface Document Guidelines; First Edition 1.1 This bulletin provides guidance on information that is to be shared

    regarding well construction and rig-specific operating guidelines. It is intended to align the lease operator’s safety and environmental management system (SEMS) with drilling contractor’s safe work practices (CSWP).

    1.2 The well construction interface document (WCID) is used to formalize the exchange of information as shown in Figure 1.

    NOTE The WCID is not intended to duplicate the health, safety, and environment (HSE) information addressed by the lease operator’s HSE bridging document with the drilling contractor.

    1.3 The WCID-SEMS is a bridging document that includes the elements identified in API 75 within the context of well construction activities. It is understood that work processes vary between operators and contractors, which should be honored in the development of the WCID document.

    1.4 The intent of the bridging document between the lease operator’s SEMS and the CSWP is to provide:

    a) an outline of responsibilities for the lease operator’s and drilling contractor’s personnel;

    b) acknowledgement that management of change (MOC) and risk assessment processes should be used:

    — during well construction activities,

    — to address personnel or organizational changes to ensure personnel skill level is sufficient for the applicable position;

    c) a vehicle for the drilling contractor to be involved when operational changes and/or conditions are identified that could require a well activity risk assessment;

    d) a method to align all parties with regard to drilling HSE standards and applicable regulatory requirements;

    e) a method of communicating stop work authority.

    1.5 The WCID-well plan contains the following elements (shown in Figure 1):

    a) well design:

    — location and environment,

    — geological and geophysical;

    b) well barrier plan risk identification;

    c) well execution plan.

    1.6 To enhance safe operations, the well plan provides a basis for discussion of well construction equipment, barriers, risks, and the mitigations for those risks.

    EXAMPLE Drilling contractor rig-specific operating guideline examples:

    a) well control practices:

    — shut-in procedures,

    — blowout preventer (BOP) configuration;

    b) equipment constraints:

    — rig capacity;

    c) well-specific operating guidelines:

    — watch circle.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/f98f283d-b5cf-431b-bd52-6234a397d45a.htm 01-Dec-13
    API BUL D15 1ST ED (R 1983) Recommendations for Proper Usage and Handling of Inhibited Oilfield Acids; 1st Edition This section suggests some guidelines that can be followed to minimize acid corrosion problems, including general corrosion, pitting, and stress cracking. Suggestions pertaining to preparation of the well, preparation of the acid solution, injection of the acid solution, and subsequent clean up of the well are presented. While all these guidelines may not be applicable for each acid treatment, their merits should be carefully weighed.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/ee4f77ab-88de-48e7-990c-4dc980eb1eda.htm 01-Mar-83
    API BUL E1 2ND ED (E1) Bulletin on the Generic Hazardous Chemical Category List and Inventory for the Oil and Gas Exploration and Production Industry; Superfund Amendments and Reauthorization Act of 1986, Emergency Planning and Community Right-to-Know Act, Title III Sections 311 and 312; Bulletin E1 (BUL E1); Second Edition, December 1, 1990; Errata; September 1, 1991 Under sections 311 and 312 of the Superfund Amendments and Reauthorization Act of 1986 (SARA Title III), also known as the Emergency Planning and Community Right to Know Act of 1986 (EPCRA) (42 U.S.C. Sections 11021, 11022) owners or operators of oil and gas exploration and production (E&P) facilities must provide to state and local emergency response agencies information on the hazardous chemicals they produce or use in production, drilling, workover, and completion operations. Because the SARA Title III reporting requirements were basically designed to allow communities to plan for emergencies at major industrial sites, they have presented difficulties to E&P operators. E&P operators have thousands of leases throughout the country and millions of pieces of equipment on the leases. They employ hundreds of contractors who use a wide variety of chemicals at production sites for short periods of time. Generic reporting, a simplified means of compliance, was developed in response to the problems which SARA Title III reporting requirements create for the E&P industry. The American Petroleum Institute (API) believes the generic reporting approach out lined in this publication (1) can satisfy section 311 and 312 reporting requirements and (2) will be benefit emergency response agencies in planning for or responding to an emergency situation. The Environmental Protection Agency (EPA) agrees the generic reporting concept can meet section 311 and 312 reporting requirements under certain conditions (see Appendix A). State Emergency Response Commissions in most producing states also accept generic reporting. Facility Operators should check with the appropriate authorities. API encourages you to review this publication carefully. It contains the filing instructions, generic reports and a detailed explanation of their development and use. The generic reports have been developed to assist in preparing reports under sections 311 and 312 of SARA Title III and should be subject to your independent legal review.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ba5c6beb-e9b5-4375-a60c-cb0de5508eca.htm 01-Dec-90
    API BUL E1 2ND ED (R 2000) Bulletin on the Generic Hazardous Chemical Category List and Inventory for the Oil and Gas Exploration and Production Industry; Superfund Amendments and Reauthorization Act of 1986, Emergency Planning and Community Right-to-Know Act, Title III Sections 311 and 312; Second Edition; Reaffirmed, June 2000 Under sections 311 and 312 of the Superfund Amendments and Reauthorization Act of 1986 (SARA Title III), also known as the Emergency Planning and Community Right to Know Act of 1986 (EPCRA) (42 U.S.C. Sections 11021, 11022) owners or operators of oil and gas exploration and production (E&P) facilities must provide to state and local emergency response agencies information on the hazardous chemicals they produce or use in production, drilling, workover, and completion operations. Because the SARA Title III reporting requirements were basically designed to allow communities to plan for emergencies at major industrial sites, they have presented difficulties to E&P operators. E&P operators have thousands of leases throughout the country and millions of pieces of equipment on the leases. They employ hundreds of contractors who use a wide variety of chemicals at production sites for short periods of time. Generic reporting, a simplified means of compliance, was developed in response to the problems which SARA Title III reporting requirements create for the E&P industry. The American Petroleum Institute (API) believes the generic reporting approach outlined in this publication (1) can satisfy section 311 and 312 reporting requirements and (2) will be benefit emergency response agencies in planning for or responding to an emergency situation. The Environmental Protection Agency (EPA) agrees the generic reporting concept can meet section 311 and 312 reporting requirements under certain conditions (see Appendix A). State Emergency Response Commissions in most producing states also accept generic reporting. Facility Operators should check with the appropriate authorities. API encourages you to review this publication carefully. It contains the filing instructions, generic reports and a detailed explanation of their development and use. The generic reports have been developed to assist in preparing reports under sections 311 and 312 of SARA Title III and should be subject to your independent legal review.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/188385de-9284-420b-a77b-95e860f1e581.htm 01-Dec-90
    API BUL E2 2ND ED (2006) Bulletin on Management of Naturally Occurring Radioactive Materials (NORM) in Oil and Gas Production; Second Edition Naturally occurring radioactive materials (NORM) are present in oil and gas operations at some locations and can deposit in well tubulars, surface piping, vessels, pumps, and other producing and processing equipment. The purpose of this document is to inform oil and gas operators of the possible presence of NORM and to provide relevant information on protecting workers, the public, and the environment. The objective of this document is to provide general information to users so that they have an under-standing of the fundamental radiation issues associated with the management of NORM. Issues where the advice of a professional health physicist, industrial hygienist, or other technical expert may be useful are identified and guidance provided. Readers are advised to contact their state regulatory office and work very closely with that office on all NORM issues.

    Radiation can result from both man-made and natural sources. Man-made sources include dental x-rays and well logging tools. Natural sources of radiation include the sun (cosmic rays) and radiation from naturally occurring materials found in the earth's crust and in living organisms. Radioactive materials are unstable and decay over time, emitting ionizing radiation. If body tissue or organs are exposed to excessive radiation, biological damage can occur in the individuals exposed or in their descendants, increasing the risk of cancer or birth defects. Thus, it is important to protect humans from unnecessary exposure to excessive levels of radiation.

    NORM is found throughout the natural environment and in man-made materials such as building materials and fertilizer, as well as in association with some oil and gas production. NORM found in oilfield operations originates in subsurface oil and gas formations and is typically transported to the surface in produced water. As the produced water approaches the surface and its temperature drops, precipitates form in tubing strings and surface equipment. The resulting scales and sludges may contain radium and radium decay products as well as other uranium and thorium progeny. In addition, radon is sometimes contained in produced natural gas and can result in the formation of thin radioactive lead films on the inner surfaces of gas processing equipment.

    Measurements on the outer surfaces of equipment containing NORM usually indicate levels of radiation that are below levels considered to be of concern. When equipment is opened for inspection or repair, inhaling or ingesting NORM can expose personnel to radioactivity. Therefore, in these situations, workers should take precautions to prevent the generation of dust and wear protective equipment. It is also important that NORM waste or equipment containing NORM be managed and disposed by methods that protect the public from unnecessary exposure.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/62a05cd1-7f8e-4758-92c8-06e321a387d9.htm 01-Apr-06
    API BUL E3 1ST ED (R 2000) Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations; First Edition; Reaffirmed, June 2000 This document, prepared by the API Underground injection

    Control Issue Group (UICIG), provides guidance on environmentally-sound abandonment practices for wellbores drilled for oil and gas exploration and production (E&P) operations. The guidance is focused primarily on onshore wells. Guidance is provided for the practices that may be used and for the selection and placement of materials necessary to accomplish the following:

    • Permanently abandon wells.

    • place web on inactive status.

    Permanent abandonment should be performed when there is no further utility for a wellbore by sealing the wellbore against fluid migration. Inactive well practices may be performed when a wellbore has future utility, such as for enhanced oil recovery projects. This permits the operator to hold the well in a condition that facilitates restoring its Utility.

    The purpose of this document is to address the environmental concerns related to well abandonment and inactive well practices. The primary environmental concerns are protection of freshwater aquifers b m fluid migration, as well as isolation of hydrocarbon production and water injection intervals. Additional issues discussed herein are protection of surface soils and surface waters, future land use, and permanent documentation of plugged and abandoned (P&A) wellbore locations and conditions.

    The guidance contained in this document is presented by the following process:

    1. Discussing a methodology for assessing the contamination potential of wells.

    2. Describing the environmental concerns that justify proper wellbore abandonment procedures.

    3. Describing permanent plugging and abandonment procedures.

    4. Establishing risk based guidelines for monitoring inactive wells.

    5. Summarizing major environmental legislation and associated regulations applicable to wellbore abandonments.

    API encourages use of well abandonment practices based on the methods presented in this document. API also supports any Federal and state well abandonment programs consistent with its guidance. There are numerous Federal and state statutes, rules, and regulations specifying proper well abandonment practices. Users of this document should review the current requirements of Federal, state, and local regulations to ensure that this guidance is consistent with those regulatory requirements.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ffa7c249-977c-4694-b803-4aab5bf37197.htm 31-Jan-93
    API BUL E3 2ND ED (2018) Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations; Second Edition This document provides guidance for the design, placement, and verification of cement plugs in wells that are to be temporarily or permanently abandoned. Wells that are temporarily abandoned have intent to re-enter in the future. The placement of barriers vary depending on whether the well is to be temporarily or permanently abandoned.

    The information in this document is general in nature. Wellbore plugging and abandonment practices will vary with regulation, well type, and purpose. Sound engineering and operational practices should be applied to each plugging operation. Plug lengths are not considered in this document. Local regulations must be considered in the design as they may dictate the length of cement to be placed below or above specific intervals, or both.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6771316e-4e25-43c0-b2d9-e1c3d47d69b0.htm 01-Apr-18
    API DP 074 (1993) Current Status of Watershed Management in the United States The current focus on watershed management within the United States reflects the view that water resources are best managed on a hydrologic level and that a watershed approach should be emphasized in future Clean Water Act (CWA) reauthorization. Possible CWA amendments could provide new authority for watershed planning and management as well as possibly provide supplementary funding mechanisms, implementation of management practices would generally remain on the state, regional, and local levels.

    Presently the federal government provides a framework for watershed management programs though the creation of potential funding sources, technical assistance, and water resource regulations. In order to carry our these regulations, the federal government delegates water resource management to individual states. State agencies in conjunction with regional and local institutions are often a mechanism for implementing projects within individual watersheds. On occasion local watershed agencies enact site-specific regulations in deal with localized problems, while still abiding by state and federal water laws. The distribution of authority between federal, state, and local agencies allows management programs to focus on problems unique to individual watersheds. Currently, a multitude of watershed management institutions exist throughout the country, many of which are not mandated by federal law.

    If future CWA legislation were to further encourage the application of watershed management techniques nationwide, all sectors of society would be affected. In order to understand the current status of watershed management in the US and the operational structure of active watershed programs, this paper reviews watershed approaches, both in theory and practice, and utilizes a case study approach of individual watershed programs and institutions. Details of individual case studied are organized under the following eight headings: introductory remarks; general characteristics; water quality problems; implementation factors - authority and funding; program infrastructure; non point source pollution (NPS) management programs, petroleum related activity; and program accomplishments.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/1e8dbc7e-56f7-4a9d-9030-ac4f4e4c60a2.htm 01-Nov-93
    API DP 077 (1995) Alternative Wetland Mitigation Programs 1 Introduction

    Wetlands contribute much to society. They provide a habitat for fish, birds, and other wildlife, contributing to biodiversity in the process. The perform hydrologic functions (e.g., flood peak reductions, shoreline stabilization, ground water recharge) and improve water quality through sediment accretion and nutrient uptake (National Research Council, 1992). Additionally, they provide society with areas for recreation and research. However, since most of the benefits of leaving a wetland in its natural state flow to the public at large, and not the landowner, there exists significant pressure for landowners, (who one 74 percent of all remaining wetlands, CEQ, 1989) to convert their wetlands to upland habitat suitable for agriculture, silviculture, and development. Therefore, it is not surprising that over half of the country’s initial 200 million wetland acres have been converted to other landscapes (Frayer et al., 1983). Eighty-seven percent of all wetland losses between 1955 and 1975 were the result of agricultural activity. Urban development activities accounted for and additional 8 percent of losses and all other causes, including natural processes (particularly subsidence and compaction in the Gulf of Mexico coastal wetlands), accounted for the remaining 5 percent of wetland losses (Tiner, 1984).

    A general outcry over wetlands loss prompted state and federal legislators and regulators to address the problem. The most significant pieces of federal wetlands legislation is section 404 of the Clean Water Act, which general requires individuals to obtain a permit from the Army Corp of Engineers (Corps) before filling wetlands. Obtaining a permit requires the applicant to prove that there are no alternative locations for development activity, prove that wetland losses are minimized, and provide compensation for the remaining unavoidable losses by restoring, enhancing, creating, or ( in limited cases) preserving wetlands.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/79077074-b5ba-445e-981a-7274a3cb180f.htm 01-Feb-95
    API DP 081 (1995) Policy Analysis and Strategic Planning Department: Are We Running Out of Oil? Since the dawn of the petroleum industry in the mid 19th century, there have been recurrent waves of concern that exhaustion of the world’s petroleum resource base was imminent. In the light of historical hindsight, such concerns of exhaustion have been obviously premature. Despite the inevitability of an eventual peak and decline in world oil production at some future date, there is little empirical evidence to suggest that such a date will be any time soon, or that it will result from global resource exhaustion.

    In fact, the available empirical evidence suggests just the opposite -- by most measures, world oil resources are more abundant today than ever before. World production in recent years has resumed the growth that was briefly interrupted in the 70’s and early 80’s (though at a lower rate), as seen in Figure 1.

    World production rose more than sixfold between 1950 and its peak in 1979 (at nearly 63 million barrels a day). After a sharp decline in the first half of the 80’s attributable to the Iran/Iraq war and an ultimately futile attempt by OPEC to defend an unrealistic price, supply began growing again after 1985, averaging about 1.4% per year since that time, and is expected to soon surpass the previous peak.

    Despite this massive expansion of supply, there is little evidence of the effects of depletion available in the historical record. As seen in Figure 2, in 1950 proven reserves were 90 billion barrels, sufficient to sustain production at the 1950 rate for about 24 years. By 1993, reserves had expanded to nearly a trillion barrels, sufficient to support 1993 levels of production for another 45 years. Moreover, this more than tenfold expansion of proven reserves occurred despite the fact that 650 billion barrels had been consumed in the interim. However, there may be less here than meets the eye.

    “Proven reserves” do not, have not, and were never intended to provide a measure of remaining resources, or even an approximation to such a measure. Rather, they are and always have been defined to represent a working inventory, continually replaced by new exploration and development. Current reserve estimates no more represent the remaining supply of oil resources than current inventories of groceries on the shelf are a measure of future food supplies3. Nonetheless, the level of proven reserves at any point does say something about future supply potential. Namely, it generally provides a lower bound on remaining resource potential4, rather than the upper bound it is often misinterpreted to represent

    That upper bound, the amount of oil remaining in the earth, is clearly finite and, unlike proven reserves, clearly declines with cumulative production. However, its magnitude is unobservable, and more importantly, it is not clearly even relevant to the imminence of exhaustion. That is, oilfields are typically abandoned far before the oil in place is completely removed. On average, only about a third of the oil is recovered at the point where it typically becomes technically or economically impractical to continue production.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/eaccf4c0-2ba1-49fe-8a33-0d300e1733e1.htm 01-Dec-95
    API DP 084R (1996) Analysis of the Costs and Benefits of Regulations: A Review of Hisorical Experience A central theme of recent efforts at regulatory reform legislation is that legislators and regulators should take into account the monetized benefits and costs of alternatives, and choose those alternatives which maximize net benefits. It is argued that the use of this criteria will make society as a whole better off.

    This paper examines a part of the historical record on the use of benefit-cost analysis in the federal government regulator arena. The purpose of this examinations to learn what has and has not been done with past analyses, what kinds of analyses are feasible, and most importantly, what is necessary to male good use of economic criteria in regulatory decision making.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b5bcc3dc-eceb-47b0-af0b-7517fcb6ce9f.htm 01-Dec-96
    API DP 088 (1997) Restoring Natural Resources: Legal Background and Economic Analysis Over the past eleven years, the Department of the Interior (Interior) and National Oceanic and Atmospheric Administration (NoAA) have developed relations to assess liability for damages to public natural resources under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and Oil Pollution Act (OPA) Respectively. The goal of these regulations is unambiguous: restoration of the injured resource. What is unclear is the goal of restoration. It is to restore the resource’s physical, chemical, and biological characteristics, or is it to restore the services provided by the resource? In some places, the regulations appear to adopt one position, while in other places they appear to support the other.

    Am additional question is , if services are the focus of restoration, what services should be addressed? Should it be all services , regardless of whether humans place any value on them, or should it be limited to human services- those services that the public cares about? The regulations appear to require the restoration of all services, arguing that ecological services are generally linked to those things the public cares about.

    Depending on which objectives are chosen, large quantities of productive resources could be consumed in activities that would generate few, if any, commensurate public benefits.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/ce67733e-b9f0-42db-9e29-c5399ff40a3e.htm 01-Oct-97
    API DR 076 (1994) Federal Subsidies for Alternative Fuels and Alternative-Fuel Vehicles; September 1994 This paper reviews the many federal programs supporting alternative (non-petroleum) fuels and alternative fuel vehicles.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/48e727ad-a204-4030-8cf4-2af4d922c75a.htm 01-Sep-94
    API E5 2ND ED (1997) Environmental Guidance Document: Waste Management in Exploration and Production Operations; Second Edition This document reflects our industry’s continuing commitment to environmental protection. It provides guidance for minimizing the direct and indirect environmental impacts of solid wastes originating from typical exploration and production (E&P) activities, which include exploration, drilling, well completions and workovers, field production, and gas plant operation. This manual was prepared by the API Production Waste Issues Group, under the jurisdiction of the API Exploration and Production Department Executive Committee on Environmental Conservation. The oil and gas industry must operate where oil and gas deposits are found. This means that the exploration and production activities listed above will be conducted in a variety of ecosystems, whose sensitivity to the activities of man will vary widely. The oil and gas industry must be environmental stewards in two critical ways: a. It must use environmentally sound operating practices to manage materials, land, and the waste generated from exploration and production activities. b. It must produce oil and gas reserves as efficiently and prudently as possible in order to prevent squandering critical natural resources.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a630ab55-ea11-4999-8688-92012c730dbd.htm 01-Feb-97
    API EPA GUIDANCE FOR SRR UNDER TSCA (2008) Summary for API Members of EPA Guidance for Substantial Risk Reporting Under TSCA Section 8(e); Reference Documents Included; November 2008 The purpose of this document is to provide a summary of EPA guidance for

    reporting substantial risk information under Toxic Substances Control Act (TSCA) Section 8(e), for use by API and its member companies. EPA’s guidance for reporting under TSCA Section 8(e) exists in various sources. The information below provides references to EPA guidance and summarizes the guidance in consolidated, condensed form. When making case-by-case decisions on whether to submit information, it is important to consult the original EPA guidance relevant to the issues at hand.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ea17e791-f886-4b35-aede-f6ef6f20d43a.htm 01-Nov-08
    API ETHANOL STUDY (2002) Impact of Gasoline Blended with Ethanol on the Long-Term Structural Integrity of Liquid Petroleum Storage Systems and Components; Literature Review; Executive Summary; June 2002 This report summarizes the results of a literature review conducted for the American Petroleum Institute on the impact of gasoline blended with ethanol on the long-term structural integrity of liquid petroleum storage systems and components.

    It is anticipated that the use of ethanol in motor fuels will continue to increase. This has generated interest about the potential long-term structural effects of ethanol on liquid petroleum storage systems, including underground storage tanks (USTs), underground piping, and associated components.

    The objective of the literature review is to determine the state of industry knowledge and research on the effects of ethanol/gasoline blends on the long-term structural integrity of UST systems and components. This review is intended to assist decision-makers on further research requirements and needed changes or supplements to existing standards for underground storage systems and components used for storing and dispensing gasoline blended with ethanol.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d813c975-4b14-4180-9abd-a23e8bd164a2.htm 01-Jun-02
    API GUIDE HF3 1ST ED (2011) Practices for Mitigating Surface Impacts Associated with Hydraulic Fracturing; First Edition The purpose of this guidance document is to identify and describe practices currently used in the oil and natural gas industry to minimize surface environmental impacts—potential impacts on surface water, soils, wildlife, other surface ecosystems and nearby communities—associated with hydraulic fracturing operations. While this document focuses primarily on issues associated with operations in deep shale gas developments, it also describes the important distinctions related to hydraulic fracturing in other applications.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3464735e-d3f6-4006-9ed4-1ffec2ca055e.htm 01-Jan-11
    API GUIDELINES PROPERTY DEVELOPMENT (2009) Guidelines for Property Development; American Petroleum Institute; 2009 The liquid petroleum pipeline industry has developed these guidelines to improve understanding and increase awareness of the nature of underground pipelines that transport oil, petroleum products, natural gas liquids and other hazardous liquids (collectively “pipelines” or “pipeline” throughout this document) and how to conduct land development and use activity near pipeline rights-of-way.

    The guidelines are intended for use by anyone who is involved in land development, agriculture and excavation/construction activities near a pipeline. The industry’s goal is to protect public safety of the people who live and work along pipeline rights-of-way, protect the environment along rights-of-way, and maintain the integrity of the pipeline so that petroleum products can be delivered to customers safely and without interruption.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f38e0034-e935-454c-9d26-67df7ccc4a3d.htm 01-Jan-09
    API GUIDELINES ROW ACTIVITIES (2018) Guidelines for Right-of-Way Activities; American Petroleum Institute; 2018 The liquid petroleum pipeline industry has developed these guidelines to improve understanding and increase awareness of the nature of underground pipelines that transport oil, petroleum products, natural gas liquids and other hazardous liquids (collectively “pipelines” or “pipeline” throughout this document) and how to conduct land development and use activity near pipeline rights-of-way.

    The guidelines are intended for use by anyone who is involved in land development, agriculture and excavation/construction activities near a pipeline. The industry’s goal is to protect public safety of the people who live and work along pipeline rights-of-way, protect the environment along rights-of-way, and maintain the integrity of the pipeline so that petroleum products can be delivered to customers safely and without interruption.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/45465281-6a3d-4ec3-b82e-3b4d963adebe.htm 01-Aug-18
    API HUMAN FACTORS IN NEW FACILITY DESIGN TOOL 2ND ED (2005) Human Factors in New Facility Design Tool; API Human Factors Task Force; Regulatory Analysis & Scientific Affairs Department; Second Edition, October 2005 This document focuses only on equipment design. Items such as human error, behavior-based safety, and operating procedure issues are not in the scope.

    The Tool covers equipment that is common to both upstream producing and downstream manufacturing operations. Equipment associated with specific activities, such as drilling rigs is not specifically addressed. The human factors principles described in this document are intended for new equipment designs; however, many ideas provided in this Tool may be used to improve the operation of existing plants, where feasible.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/0c1b472f-a823-4bf0-94ce-49ece822eb4c.htm 28-Jul-16
    API HUMAN FACTORS PHA (2004) Tool for Incorporating Human Factors During Process Hazard Analysis (PHA) Reviews of Plant Designs; API Human Factors Task Force; Regulatory Analysis & Scientific Affairs Department The following tool contains screening questions for incorporating human

    factors in process design. To make the tool more useful, example situations and potential solutions were added. Please note that it is not a comprehensive listing of all scenarios. In addition, your company may have different company-specific requirements that vary from those in the potential solution column. These Human Factors guidelines are not meant to be applied retroactively to existing plants, but are intended for future designs. See Glossary for definitions of underlined words.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/69c6c269-732b-4f48-a7e5-63b56f1af9bb.htm 01-Mar-04
    API MPMS CHAPTER 15 3RD ED (R 2015) Guidelines for the Use of the International System of Units (SI) in the Petroleum and Allied Industries; Third Edition; Reaffirmed, February 2015 This publication specifies the API preferred units for quantities involved in petroleum industry measurements and indicates factors for conversion of quantities expressed in customary units to the API preferred metric units. The quantities that comprise the tables are grouped into convenient categories related to their use. They were chosen to meet the needs of the many and varied aspects of the petroleum industry but also should be useful in other, similar process industries.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c84eb3c4-a017-40ee-b9ff-dc2359133c90.htm 01-May-06
    API MPMS CHAPTER 15 4TH ED (2019) Guidelines for the Use of Petroleum Industry-specific International System (SI) Units; Fourth Edition 1 Scope and Field of Application

    This publication specifies the API-preferred units for quantities involved in petroleum industry measurements, and indicates factors for conversion of quantities expressed in customary units to the API-preferred SI units not covered i n ASTM/IEEE SI-10. The quantities that comprise the tables are grouped into convenient categories related to their use. They were chosen to meet the needs of the many and varied aspects of the petroleum industry, but also should be useful in other, similar process industries.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/bf7b95b4-4691-42da-ba47-aeb28df9c2ad.htm 01-Jun-19
    API OSRC 1ST ED (2015) Proceedings of the 2014 Offshore Structural Reliability Conference; September 16-18, 2014; Houston, Texas The manner in which reliability is applied to structural engineering is different from most other forms of engineering. Other engineering disciplines tend to consider reliability in the context of the performance of many thousands of identical precision made components where physical and performance tests can be used to quantify product reliability. Structures, which may involve many thousands of tonnes of material and site assembly, are not identical and cannot normally be physically tested on completion. Reliability is therefore addressed in the design and fabrication standards.

    This paper addresses the early development of structural reliability as a concept, initial applications to standards development and how it has been incorporated in the International Standards Orgainisation (ISO) Offshore Structures Standard.

    Offshore Structures designed and fabricated to current standards have in general a satisfactory reliability. An overview of where the industry is in terms of reliability is provided.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/e152c19c-889b-495d-824f-e41ccbf2d26b.htm 01-Sep-14
    API PROCEDURE FOR STD DEV 4TH ED (2012) Procedures for Standards Development; American Petroleum Institute; Fourth Edition; ANSI Approved: September 2001; Revised: September 2012 1.1 API Standards Committees

    The procedures established in this document govern the development of standards published by the American Petroleum Institute (API). All API standards development activities shall be conducted in accordance with these Procedures.

    API committees responsible for standards development may also maintain written procedures addressing individual committee organization, scope, membership and conduct. These Procedures shall not be amended by individual committee procedures or procedures developed for joint committee activities (see 1.2).

    Questions regarding intellectual property issues such as copyrights, trademarks or patents shall be directed to the API Office of General Counsel.

    1.2 Joint Committees

    API committees working jointly with other standards developing organizations shall maintain written procedures addressing joint committee structure, scope, membership and operations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d1c82a02-06b8-4c3c-a687-22dcfff7cc44.htm 01-Jan-12
    API RP 10B-2 2ND ED (2013) Recommended Practice for Testing Well Cements; Second Edition This standard specifies methods and gives recommendations for the testing of cement slurries and related materials under simulated well conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/26a875ea-7a2b-452b-9d6a-d32becc802a7.htm 01-Apr-13
    API RP 10B-2 2ND ED (R 2019) Recommended Practice for Testing Well Cements; Second Edition This standard specifies methods and gives recommendations for the testing of cement slurries and related materials under simulated well conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3c1808c7-6312-4b8d-b3de-291ef79704c5.htm 01-Apr-13
    API RP 10B-3 2ND ED (2016) Testing of Well Cements Used in Deepwater Well Construction; Second Edition This recommended practice provides procedures for testing well cement slurries and cement blends for use in a deepwater environment or wells drilled in areas with a low seafloor temperature or areas where low well temperatures exist. For the purposes of this document the term “deepwater” includes areas where low seafloor temperatures exist, independent of water depth.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/f6bd6660-8827-474d-96f2-3d3a59996373.htm 01-Jan-16
    API RP 10B-3 2ND ED (R 2020) Testing of Well Cements Used in Deepwater Well Construction; Second Edition This recommended practice provides procedures for testing well cement slurries and cement blends for use in a deepwater environment or wells drilled in areas with a low seafloor temperature or areas where low well temperatures exist. For the purposes of this document the term "deepwater" includes areas where low seafloor temperatures exist, independent of water depth.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/cb06e87c-b4a1-4b4b-b8d1-98eeca73fd41.htm 01-Jan-16
    API RP 10B-4 2ND ED (2015) Preparation and Testing of Foamed Cement Formulations at Atmospheric Pressure; Second Edition 1 Scope

    This standard defines the test methods including the generation of unfoamed base and their corresponding foamed cement slurries at atmospheric pressure. These procedures are developed for foaming cement slurries with air, at atmospheric conditions, which could mimic a foam quality experienced with nitrogen at downhole conditions; they may be modified to accommodate other gases such as nitrogen. Slurries that are foamed with nitrogen, and their properties, will also be discussed within this standard as they are relevant to the scope of the standard.

    This standard does not address testing at pressures above atmospheric conditions, nor does this standard include or consider the effects of nitrogen solubility in the nitrogen fraction calculations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5a351787-570c-4fd6-a0c1-a585c6e06418.htm 01-Oct-15
    API RP 10B-4 2ND ED (R 2019) Preparation and Testing of Foamed Cement Formulations at Atmospheric Pressure; Second Edition; Reaffirmed August 2019 1 Scope

    This standard defines the test methods including the generation of unfoamed base and their corresponding foamed cement slurries at atmospheric pressure. These procedures are developed for foaming cement slurries with air, at atmospheric conditions, which could mimic a foam quality experienced with nitrogen at downhole conditions; they may be modified to accommodate other gases such as nitrogen. Slurries that are foamed with nitrogen, and their properties, will also be discussed within this standard as they are relevant to the scope of the standard.This standard does not address testing at pressures above atmospheric conditions, nor does this standard include or consider the effects of nitrogen solubility in the nitrogen fraction calculations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fb838bbe-216a-4ce8-b14a-e78ae9057e1a.htm 01-Oct-15
    API RP 10B-6 1ST ED (R 2015) Recommended Practice on Determining the Static Gel Strength of Cement Formulations; First Edition; Reaffirmed, April 2015; ISO 10426-6:2008 This part of ISO 10426 specifies requirements and provides test methods for the determination of static gel strength (SGS) of cement slurries and related materials under simulated well conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9d6b6821-e4db-400b-8d19-6ad413652c78.htm 01-Aug-10
    API RP 10B-6 1ST ED (R 2019) Recommended Practice on Determining the Static Gel Strength of Cement Formulations; First Edition; Reaffirmed, December 2019; ISO 10426-6:2008 This part of ISO 10426 specifies requirements and provides test methods for the determination of static gel strength (SGS) of cement slurries and related materials under simulated well conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/44cacd5a-3dd7-40e8-a94e-a03f23d524ac.htm 01-Aug-10
    API RP 10F 3RD ED (E1) (R 2015) Recommended Practice for Performance Testing of Cementing Float Equipment; Third Edition; Reaffirmed, April 2015; ISO 10427-3:2003 This International Standard describes testing practices to evaluate the performance of cementing float equipment for the petroleum and natural gas industries.

    This International Standard is applicable to float equipment that will be in contact with water-based fluids used for drilling and cementing wells. It is not applicable to float equipment performance in non-water-based fluids.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/dc035270-033f-4bd8-a9dc-c499f39eb070.htm 01-Apr-15
    API RP 10F 3RD ED (R 2008) Recommended Practice for Performance Testing of Cementing Float Equipment; Third Edition; Reaffirmed, August 2008 This International Standard describes testing practices to evaluate the performance of cementing float equipment for the petroleum and natural gas industries.

    This International Standard is applicable to float equipment that will be in contact with water-based fluids used for drilling and cementing wells. It is not applicable to float equipment performance in non-water-based fluids.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ca8e40b8-99c2-46e8-a415-ae3299159a98.htm 01-Apr-02
    API RP 11AR 4TH ED (E1) (R 2014) Recommended Practice for Care and Use of Subsurface Pumps; Fourth Edition; Reaffirmed, January 2014 The intent of this recommended practice is to give information on the proper selection, operation and maintenance of subsurface pumps so the best economical life can be obtained

    The basic walking-beam sucker rod combination for producing fluids from the ground had its beginning in very early history. In more recent times, many advances in design and metallurgy have evolved. The method is so popular that today approximately 90 percent of all artificially lifted wells are produced by a sucker rod pump.

    The downhole sucker rod pump is only one portion of the pumping system.The other major components are the sucker rod string, the surface pumping unit and the prime mover. For proper pumping operation and long maintenance-free runs, all components of the system must be designed and sized properly, taking into account well depth, the amount and viscosity of fluids (oil, water or gas) to be produced, and abrasiveness and corrosiveness of fluids. A failure of any one of the pumping components will result in a shut down of the system, resulting in a costly repair, downtime and possible loss of production.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/1c86fa09-9301-43da-8930-d6956f9ad4f6.htm 01-Jan-14
    API RP 11AR 4TH ED (E1) (R 2020) Recommended Practice for Care and Use of Subsurface Pumps; Fourth Edition; Reaffirmed, February 2020 The intent of this recommended practice is to give information on the proper selection, operation and maintenance of subsurface pumps so the best economical life can be obtained

    The basic walking-beam sucker rod combination for producing fluids from the ground had its beginning in very early history. In more recent times, many advances in design and metallurgy have evolved. The method is so popular that today approximately 90 percent of all artificially lifted wells are produced by a sucker rod pump.

    The downhole sucker rod pump is only one portion of the pumping system.The other major components are the sucker rod string, the surface pumping unit and the prime mover. For proper pumping operation and long maintenance-free runs, all components of the system must be designed and sized properly, taking into account well depth, the amount and viscosity of fluids (oil, water or gas) to be produced, and abrasiveness and corrosiveness of fluids. A failure of any one of the pumping components will result in a shut down of the system, resulting in a costly repair, downtime and possible loss of production.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/852e99eb-85ba-43ac-9892-10acb017e5f3.htm 01-Jan-14
    API RP 11BR 9TH ED (R 2015) Recommended Practice for the Care and Handling of Sucker Rods; Ninth Edition; Reaffirmed, March 2015 This recommended practice (RP) covers the care and handling of steel sucker rods, including guidelines on selection, allowable stress, proper joint makeup, corrosion control and used rod inspection.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/623234cd-01dd-4def-9440-d100db7d7580.htm 01-Mar-15
    API RP 11ER 3RD ED (R 2015) Recommended Practice for Guarding of Pumping Units; Third Edition; Reaffirmed, March 2015 This RP is intended to provide safeguards for all persons who are required to work around or on oil well pumping units.

    a) These safeguards should prevent bodily injury from contact with moving parts by anyone inadvertently walking into, falling, slipping, tripping, or similar action. The safeguards should also prevent injury from reasonable or predictable breakage of any of the component parts.

    b) It is anticipated that persons who will be exposed to the hazards involved with the moving parts of a pumping unit are adults who are able-bodied and physically capable of performing useful work; they may be expected to be of normal intelligence and able to act with reasonable decorum and caution. They may also be expected to be aware of the potential hazards involved. The general public normally will not have access to the area where pumping units are located. Pumping units generally are in rural and fairly remote locations on private leases where the public would be trespassing.

    c) Where unattended locations present close exposure to a community of people, safety barriers, such as provided by a totally enclosed and locked perimeter, may be required.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e38fc0cf-21f7-4543-8d0e-3f26297f56d1.htm 01-Mar-15
    API RP 11G 5TH ED (2013) Recommended Practice for Installation, Maintenance, and Lubrication of Pumping Units; Fifth Edition This recommended practice provides guidance related to the proper installation, care, and maintenance of surface mounted beam pumping units, varieties of which are described in API 11E. Information provided in this document is of a general nature and is not intended to replace specific instruction provided by the pumping unit manufacturer. This document further establishes certain minimum requirements intended to promote the safe installation, operation, and servicing of pumping unit equipment


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/db7319e7-abfa-4033-8d77-69e1dca30319.htm 01-Nov-13
    API RP 11G 5TH ED (R 2019) Recommended Practice for Installation, Maintenance, and Lubrication of Pumping Units; Fifth Edition; Reaffirmed: July 2019 1 Scope

    This recommended practice provides guidance related to the proper installation, care, and maintenance of surface mounted beam pumping units, varieties of which are described in API 11E. Information provided in this document is of a general nature and is not intended to replace specific instruction provided by the pumping unit manufacturer. This document further establishes certain minimum requirements intended to promote the safe installation, operation, and servicing of pumping unit equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fcb4c498-5f8a-4179-ae3c-06e86573d11d.htm 01-Nov-13
    API RP 11PGT 1ST ED (1992) Recommended Practice for Packaged Combustion Gas Turbines; First Edition This recommended practice is intended to cover the minimum requirements for a complete self-sufficient packaged combustion gas turbine prime mover with or without driven equipment for onshore/offshore oil and gas production services. The package shall be factory assembled to the maximum extent possible as limited by the mode of transportation. All auxiliary equipment required for operating, starting, controlling, and protecting the turbine/driven equipment is included directly or by reference in this recommended practice. Specifically intended to be covered are gas turbine packages capable of continuous service firing gas fuel, liquid fuel, or both.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e3b3c79a-36c0-4beb-a49c-21f336d6a254.htm 01-May-92
    API RP 11S 3RD ED (R 2008) Recommended Practice for the Operation, Maintenance and Troubleshooting of Electric Submersible Pump Installations; Third Edition; Reaffirmed, April 2008 This recommended practice covers all of the major components that comprise a standard electric submersible pumping system, their operation, maintenance, and troubleshooting.

    It is specifically prepared for installations in oil and water producing wells where the equipment is installed on tubing.

    It is not prepared for equipment selection or application.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/99194c45-ca55-4846-b083-38fae1dc873b.htm 01-Nov-94
    API RP 11S 3RD ED (R 2013) Recommended Practice for the Operation, Maintenance and Troubleshooting of Electric Submersible Pump Installations; Third Edition; Reaffirmed, October 2013 This recommended practice covers all of the major components that comprise a standard electric submersible pumping system, their operation, maintenance, and troubleshooting.

    It is specifically prepared for installations in oil and water producing wells where the equipment is installed on tubing.

    It is not prepared for equipment selection or application.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d3aa26b0-c390-4736-83a5-525486902d5b.htm 01-Nov-94
    API RP 11S1 3RD ED (R 2008) Recommended Practice for Electrical Submersible Pump Teardown Report; Third Edition; Effective Date: December 15, 1997; Reaffirmed, April 2008 This recommended practice covers a recommended electrical submersible pump teardown report form. It also includes equipment schematic drawings which may provide assistance in identifying equipment components. It should be noted that these schematics are for generic equipment components, and there may be differences between manufacturers on the exact description or configuration of the assemblies.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/5ad55267-f2ee-445f-8230-b5abf24f7ed0.htm 01-Sep-97
    API RP 11S1 3RD ED (R 2013) Recommended Practice for Electrical Submersible Pump Teardown Report; Third Edition; Effective Date: December 15, 1997; Reaffirmed, October 2013 This recommended practice covers a recommended electrical submersible pump teardown report form. It also includes equipment schematic drawings which may provide assistance in identifying equipment components. It should be noted that these schematics are for generic equipment components, and there may be differences between manufacturers on the exact description or configuration of the assemblies.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6990a66b-8525-4f89-85c8-4a60ad26f092.htm 01-Sep-97
    API RP 11S2 2ND ED (R 2008) Recommended Practice for Electric Submersible Pump Testing; Second Edition; Effective Date: October 1, 1997; Reaffirmed, April 2008 1.1 GENERAL

    This recommended practice provides guidelines and procedures covering electric submersible pump performance testing intended to establish product consistency. These recommended practices are those generally considered appropriate for the majority of pump applications.

    1.2 COVERAGE

    This recommended practice covers the acceptance testing of electric submersible pumps (sold as new) by the manufacturer, vendor, or user to the following prescribed minimum specifications. This recommended practice does not include other electric submersible pump system components.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/6fba2032-a4a7-4089-8860-b649166e6610.htm 01-Aug-97
    API RP 11S2 2ND ED (R 2013) Recommended Practice for Electric Submersible Pump Testing; Second Edition; Effective Date: October 1, 1997; Reaffirmed, October 2013 1.1 GENERAL

    This recommended practice provides guidelines and procedures covering electric submersible pump performance testing intended to establish product consistency. These recommended practices are those generally considered appropriate for the majority of pump applications.

    1.2 COVERAGE

    This recommended practice covers the acceptance testing of electric submersible pumps (sold as new) by the manufacturer, vendor, or user to the following prescribed minimum specifications. This recommended practice does not include other electric submersible pump system components.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/bfc1fcf1-c62a-4512-8f79-46ab9add26ed.htm 01-Aug-97
    API RP 11S3 2ND ED (R 2008) Recommended Practice for Electrical Submersible Pump Installations; Second Edition; Reaffirmed, April 2008 1.1 This recommended practice covers the installation and replacement of all major components that comprise a typical, electrical submersible pumping system. (See Figure 1.) Specifically, it covers installations in oil and gas production operations where the equipment is installed on tubing. It does not cover equipment selection or application.

    1.2 Any of several installation procedures may be acceptable for good operations. All installations, however, require good engineering practice, sound judgment, and proper maintenance.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f46a12d0-49c3-4d5b-9878-cf4f83330a32.htm 01-Mar-99
    API RP 11S3 2ND ED (R 2013) Recommended Practice for Electrical Submersible Pump Installations; Second Edition; Reaffirmed, October 2013 1.1 This recommended practice covers the installation and replacement of all major components that comprise a typical, electrical submersible pumping system. (See Figure 1.) Specifically, it covers installations in oil and gas production operations where the equipment is installed on tubing. It does not cover equipment selection or application.

    1.2 Any of several installation procedures may be acceptable for good operations. All installations, however, require good engineering practice, sound judgment, and proper maintenance.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/dccb35c6-0ea4-439e-bc11-34feab6afe23.htm 01-Mar-99
    API RP 11S4 3RD ED (2002) Recommended Practice for Sizing and Selection of Electric Submersible Pump Installations; Third Edition Each component of the ESP system (pump, motor, intake, seal or protector, cable, switchboard, etc.) is discussed in some detail as far as what must be considered for the best selection at a desired rate and well conditions. Examples are given to illustrate the basic design procedure and illustrate how PVT correlations, multiphase flow correlations, and inflow performance relationships are used.

    Summary designs and computer examples using the detailed design principles are presented which show how design considerations fit together, and how tools such as computer programs allow faster solutions resulting in easier trial and error calculations for optimization of designs and study of existing installations.

    Topics such as PVT correlations, multiphase flow correlations, and inflow performance relationships are discussed in the appendices.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/1772b71a-0593-4632-b22f-06892265050a.htm 01-Jul-02
    API RP 11S4 3RD ED (R 2008) Recommended Practice for Sizing and Selection of Electric Submersible Pump Installations; Third Edition; Reaffirmed, April 2008 Each component of the ESP system (pump, motor, intake, seal or protector, cable, switchboard, etc.) is discussed in some detail as far as what must be considered for the best selection at a desired rate and well conditions. Examples are given to illustrate the basic design procedure and illustrate how PVT correlations, multiphase flow correlations, and inflow performance relationships are used.

    Summary designs and computer examples using the detailed design principles are presented which show how design considerations fit together, and how tools such as computer programs allow faster solutions resulting in easier trial and error calculations for optimization of designs and study of existing installations.

    Topics such as PVT correlations, multiphase flow correlations, and inflow performance relationships are discussed in the appendices.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/05a5eb79-b3e0-4d1f-a5f1-3e6e9907f234.htm 01-Jul-02
    API RP 11S4 3RD ED (R 2013) Recommended Practice for Sizing and Selection of Electric Submersible Pump Installations; Third Edition; Reaffirmed, October 2013 Each component of the ESP system (pump, motor, intake, seal or protector, cable, switchboard, etc.) is discussed in some detail as far as what must be considered for the best selection at a desired rate and well conditions. Examples are given to illustrate the basic design procedure and illustrate how PVT correlations, multiphase flow correlations, and inflow performance relationships are used.

    Summary designs and computer examples using the detailed design principles are presented which show how design considerations fit together, and how tools such as computer programs allow faster solutions resulting in easier trial and error calculations for optimization of designs and study of existing installations.

    Topics such as PVT correlations, multiphase flow correlations, and inflow performance relationships are discussed in the appendices.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/24a1ed29-832f-4e10-93a7-c59789bad683.htm 01-Jul-02
    API RP 11S5 2ND ED (2008) Recommended Practice for the Application of Electrical Submersible Cable Systems; Second Edition This document covers the application (size and configuration) of electrical submersible cable systems by manufacturers, vendors, or users.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/3117e7c8-adc6-46f4-b644-3defbce77d15.htm 01-Apr-08
    API RP 11S5 2ND ED (R 2013) Recommended Practice for the Application of Electrical Submersible Cable Systems; Second Edition; Reaffirmed, October 2013 This document covers the application (size and configuration) of electrical submersible cable systems by manufacturers, vendors, or users.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/1a46b6ac-c352-4723-86ed-2987b1cb354a.htm 01-Apr-08
    API RP 11S6 1ST ED (R 2008) Recommended Practice for Testing of Electric Submersible Pump Cable Systems; First Edition; Reaffirmed, April 2008 1.1 GENERAL This recommended practice covers testing of Electric Submersible h m p Cable Systems. Cable testing, in general, can be broken into two basic categories: Factory Testing and Field Testing. This recommended practice only addresses procedures for Field Testing. Factory Tests provide assurance that the finished product meets the anticipated performance criteria for the intended application. All the tests involved are used to detect gross cable defects in materials and workmanship. Typical tests on new cable include ac, dc, IR and Conductor Resistance, and are covered under such standards as IEEE 400, IEEE 1017, IEEE 1018, and IEEE 1019. One consideration of any testing is that an electrical failure may not occur on a damaged cable during the actual test since testing is done under controlled conditions relative to oil well conditions. A more costly failure may then occur with the damaged cable downhole. Testing is simply an indicator of the insulation at that time. It is not a guarantee of future performance. The test procedures and values outlined in this document are based upon accepted practices. Nevertheless, engineering judgment should be used to determine values and procedures applicable in specific situations. 1.2 ORGANIZATION This recommended practice addresses field testing of electric submersible pump cable systems. It is organized into three major topic categories. The first category provides general definitions and overview of terms, safety considerations, and cable system preparation guidelines (Sections 2-6) . The second category identifies various situations under which testing is performed (Sections 7-10). The third category identifies test methods and procedures (Sections 11-14). 1.3 JURISDICTION This document covers generally accepted practices for submersible cable systems. All applicable local, state, and national codes and regulations should be followed for each installation.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/0653ee94-5549-4450-bb2b-e044572d2ed8.htm 01-Dec-95
    API RP 11S6 1ST ED (R 2013) Recommended Practice for Testing of Electric Submersible Pump Cable Systems; First Edition; Reaffirmed, October 2013 1.1 GENERAL This recommended practice covers testing of Electric Submersible h m p Cable Systems. Cable testing, in general, can be broken into two basic categories: Factory Testing and Field Testing. This recommended practice only addresses procedures for Field Testing. Factory Tests provide assurance that the finished product meets the anticipated performance criteria for the intended application. All the tests involved are used to detect gross cable defects in materials and workmanship. Typical tests on new cable include ac, dc, IR and Conductor Resistance, and are covered under such standards as IEEE 400, IEEE 1017, IEEE 1018, and IEEE 1019. One consideration of any testing is that an electrical failure may not occur on a damaged cable during the actual test since testing is done under controlled conditions relative to oil well conditions. A more costly failure may then occur with the damaged cable downhole. Testing is simply an indicator of the insulation at that time. It is not a guarantee of future performance. The test procedures and values outlined in this document are based upon accepted practices. Nevertheless, engineering judgment should be used to determine values and procedures applicable in specific situations. 1.2 ORGANIZATION This recommended practice addresses field testing of electric submersible pump cable systems. It is organized into three major topic categories. The first category provides general definitions and overview of terms, safety considerations, and cable system preparation guidelines (Sections 2-6) . The second category identifies various situations under which testing is performed (Sections 7-10). The third category identifies test methods and procedures (Sections 11-14). 1.3 JURISDICTION This document covers generally accepted practices for submersible cable systems. All applicable local, state, and national codes and regulations should be followed for each installation.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5a24664a-fed3-438e-9dba-c05f2dc791b4.htm 01-Dec-95
    API RP 11S7 1ST ED (R 2008) Recommended Practice on Application and Testing of Electric Submersible Pump Seal Chamber Sections; First Edition; Reaffirmed, April 2008 This RP contains tutorial, testing, and failure evaluation information. It provides a general understanding of construction and functioning of seal chamber sections and identification of well conditions, system requirements and characteristics that influence component selection and application. Also included is information needed to evaluate causes of seal chamber section failures. Testing sections establish acceptable test procedures and criteria to help verify seal chamber section functionality. General shipping and handling information is also included.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/c94163b7-d44c-4f45-b394-71e84565fba9.htm 01-Jul-93
    API RP 11S7 1ST ED (R 2013) Recommended Practice on Application and Testing of Electric Submersible Pump Seal Chamber Sections; First Edition; Reaffirmed, October 2013 This RP contains tutorial, testing, and failure evaluation information. It provides a general understanding of construction and functioning of seal chamber sections and identification of well conditions, system requirements and characteristics that influence component selection and application. Also included is information needed to evaluate causes of seal chamber section failures. Testing sections establish acceptable test procedures and criteria to help verify seal chamber section functionality. General shipping and handling information is also included.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3c5b1c98-45af-45b3-9601-b506681b679f.htm 01-Jul-93
    API RP 11S8 1ST ED (R 2008) Recommended Practice on Electric Submersible System Vibrations; First Edition; Reaffirmed, April 2008 This RP covers the vibration limits, testing, and analysis of electric submersible pump systems and subsystems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/242f239a-e6d4-4f43-aa34-3687d29ecdd1.htm 01-May-93
    API RP 11S8 2ND ED (2012) Recommended Practice on Electric Submersible System Vibrations; Second Edition This Recommended Practice (RP) provides guidelines to establish consistency in the control and analysis of electric submersible pump (ESP) system vibrations. This document is considered appropriate for the testing of ESP systems and subsystems for the majority of ESP applications.

    This RP covers the vibration limits, testing, and analysis of ESP systems and subsystems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a3642913-805a-477a-8d89-a33006a77ea9.htm 01-Oct-12
    API RP 11V10 1ST ED (2008) Recommended Practices for Design and Operation of Intermittent and Chamber Gas-Lift Wells and Systems; First Edition This API document presents guidelines and recommended practices for the design and operation of intermittent, chamber, and plunger gas-lift systems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/0a338a1d-9cb8-49f4-b904-44eb5e517e41.htm 01-Jun-08
    API RP 11V2 2ND ED (R 2008) Gas-Lift Valve Performance Testing; Second Edition; Reaffirmed April 2008 Test site recommendations (Section 3): This section outlines the equipment needed for testing valves to determine the following:

    a. Valve flow coefficients (Cv).

    b. Pressure drop ratio factor (Xt).

    c. Gas-lift valve performance curves.

    Gas-lift valve probe tests (Section 4): This test method is outlined for determining the stem travel as pressure is applied over the bellows area. The test results are combined with analysis (Appendix C) to allow the user to approximate the valve load rate over the range of expected practical application conditions. The test also defines the maximum effective valve stem travel.

    Flow coefficient test procedure (Section 5): The test procedure recommends test methods required to determine the flow coefficient (Cv) as a function of stem travel. The test results, combined with analysis, allow the user to approximate the valve flow coefficient (Cv) and pressure drop ratio factor (Xt) over the range of expected practical application conditions.

    Gas-lift valve performance test methods (Section 6): This test procedure lists the test methods recommended to measure valve performance (flow) for upstream and downstream pressures and other controlled conditions.

    Use of test data (Section 7): This section recommends the number of tests which should be performed in order to acquire sufficient data to develop a model or correlation describing valve performance at conditions other than those tested. Reference is made to methods described in Appendices A and B.

    Simplified flow performance model (Appendix A): This appendix describes a method of analysis of test data that will predict flow at conditions other than those tested. The model makes several simplifying assumptions concerning valve dynamics.

    TUALP flow performance model (Appendix B): This appendix describes a method of analysis of test data that will predict flow at conditions other than those tested. The model was developed and is supported by the Tulsa University Artificial Lift Projects research program at the University of Tulsa.

    Method to analyze probe test data (Appendix C): This appendix describes a mathematical method of analysis to determine loadrate and maximum effective travel when data is collected per Section 4.

    Determination of test system time constant (Appendix D): This appendix gives the supporting explanation for the use of “ramp” functions in the test methods and describes how to determine a test systems time constant.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/8b5a4b32-5f6a-4525-a50b-600e8b999fed.htm 01-Mar-01
    API RP 11V5 3RD ED (2008) Recommended Practices for Operation, Maintenance, Surveillance, and Troubleshooting of Gas-Lift Installations; Third Edition These recommended practices are offered to assist gas-lift system operators, analysts, technicians, engineers, and others in understanding how to effectively plan, operate, maintain, troubleshoot, and provide surveillance of gas-lift systems and gas-lift wells.

    This document may be used in a gas-lift training course or as reference material. It can be obtained in booklet form as an API publication, or on CD ROM or cassette in Adobe PDF format.

    These recommended practices discuss continuous gas-lift with injection in the casing/tubing annulus and production up the tubing. Annular flow gas-lift (injection down the tubing and production up the annulus), dual gas-lift (two tubing strings in the same casing), and intermittent gas-lift are mentioned; however, most of the discussion focuses on “conventional” continuous gas-lift. Many of the recommended practices in this document may be pertinent to the other forms of gas-lift, but they should be considered and used with caution. Other recommended practices will address dual gas-lift (API 11V9) and intermittent gas-lift (API 11V10).

    This document includes:

    — Gas-lift Operating System Components and Potential Problems.

    Sections 1 through 11 describe the several components of an operating gas-lift system and discuss a number of problems that may be encountered and must be addressed to operate a gas-lift system effectively and efficiently.

    These sections are new to this edition of the document. A comprehensive checklist of system components is provided and associated problems are discussed. The list can be used when troubleshooting or de-bottlenecking a gas-lift system.

    These sections are recommended for use as:

    — part of a training course dealing with gas-lift system operation;

    — a review before beginning a major gas-lift system study;

    — a review before designing and/or modelling a gas-lift system;

    — a review before trying to troubleshoot difficult gas-lift system problems.

    — Recommended Practices for Gas-lift Operation, Maintenance, Surveillance, and Troubleshooting.

    Sections 12 through 17 are revisions/upgrades of information that has been in existence since the first edition of this document. These sections contain recommended practices for common gas-lift operations:

    — initial unloading of the completion or workover fluid from the annulus of the gas-lift well;

    — re-starting or kick off after a period of downtime;

    — adjusting or fine-tuning the gas injection rate for optimum operation.

    These sections discuss commonly used gas-lift troubleshooting tools. They conclude with sections that review the potential locations of gas-lift problems, a table of possible causes and cures of some common gas-lift system problems, and a troubleshooting checklist.

    These sections are recommended for use as:

    — part of a training course dealing with gas-lift system operation;

    — part of a training course dealing with gas-lift system maintenance;

    — a review before trying to troubleshoot a difficult gas-lift operating problem.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/686d8a95-b546-41ea-8eee-7a23a5bad820.htm 01-Jun-08
    API RP 11V5 3RD ED (R 2015) Recommended Practices for Operation, Maintenance, Surveillance, and Troubleshooting of Gas-lift Installations; Third Edition; Reaffirmed, March 2015 These recommended practices are offered to assist gas-lift system operators, analysts, technicians, engineers, and others in understanding how to effectively plan, operate, maintain, troubleshoot, and provide surveillance of gas-lift systems and gas-lift wells.

    This document may be used in a gas-lift training course or as reference material. It can be obtained in booklet form as an API publication, or on CD ROM or cassette in Adobe PDF format.

    These recommended practices discuss continuous gas-lift with injection in the casing/tubing annulus and production up the tubing. Annular flow gas-lift (injection down the tubing and production up the annulus), dual gas-lift (two tubing strings in the same casing), and intermittent gas-lift are mentioned; however, most of the discussion focuses on "conventional" continuous gas-lift. Many of the recommended practices in this document may be pertinent to the other forms of gas-lift, but they should be considered and used with caution. Other recommended practices will address dual gas-lift (API 11V9) and intermittent gas-lift (API 11V10).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/ab6862ff-8595-4cb5-8b2d-dd7dc7081434.htm 01-Mar-15
    API RP 11V6 2ND ED (R 2008) Recommended Practice for Design of Continous Flow Gas Lift Installations using Injection Pressure Operated Valves; Second Edition; Reaffirmed, April 2008 This Recommended Practice is intended to set guidelines for continuous flow gas lift installation designs using injection pressure operated valves. The assumption is made that the designer is familiar with and has available data on the various factors that affect a design. The designer is referred to the API publication Gas Lift, (Book 6 of the Vocational Training Series, Third Edition, 1994) and to the various API 11V Recommended Practices on gas lift.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/8bbabfe3-f81d-4a35-a454-aaf750a097a0.htm 01-Jul-99
    API RP 11V6 2ND ED (R 2015) Recommended Practice for Design of Continuous Flow Gas Lift Installations Using Injection Pressure Operated Valves; Second Edition; Reaffirmed, March 2015 This Recommended Practice is intended to set guidelines for continuous flow gas lift installation designs using injection pressure operated valves. The assumption is made that the designer is familiar with and has available data on the various factors that affect a design. The designer is referred to the API publication Gas Lift, (Book 6 of the Vocational Training Series, Third Edition, 1994) and to the various API 11V Recommended Practices on gas lift.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e622306c-14fd-4085-9784-8c9a9738c4ec.htm 01-Mar-15
    API RP 11V7 2ND ED (R 2008) Recommended Practice for Repair, Testing, and Setting Gas Lift Valves; Second Edition; Reaffirmed, April 2008 Recommended Practice 11V7 applies to repair, testing, and setting gas lift valves and reverse flow (check) valves. This is a recommended practice to present guidelines related to the repair and reuse of valves; these practices are intended to serve both repair shops and operators. API RP 11V7 refers to test procedures used in API Specification 11V1 and Recommended Practice 11V2. Portions of these procedures are included in the appendices of this document.

    The injection gas pressure operated (IPO) bellows valve is one example of a commonly repaired valve; the spring loaded production pressure operated (PPO) valve is also covered. Other valves, including bellows charged valves in production pressure operated service should be repaired according to the guidelines, however specialty valves are best repaired at the original manufacturer's shop.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/82b464a4-0c5c-4966-b420-abc4796a2c55.htm 01-Jun-99
    API RP 11V8 1ST ED (R 2008) Recommended Practice for Gas Lift System Design and Performance Prediction; First Edition; Reaffirmed, April 2008 This Recommended Practice (RP) is under the jurisdiction of the API Committee on Standardization of Production Equipment (Committee 11).

    This document presents RPs for the design of gas lift systems. Other API Specifications, API RPs, and Gas Processors Suppliers Association (GPSA) documents are referenced and should be used for assistance in design and operation.

    Introduction to Gas Lift System Design and Performance Prediction

    API RP 11V8 Recommended Practice for Gas Lift System Design and Performance Prediction, provides two functions:

    • A broad overview of gas lift systems and various major types of gas lift operations.

    • Recommended practices for gas lift system design and for modeling methods used in performance prediction. All key system components are reviewed to provide guidance for engineers, technicians, well analysts, and operating personnel who are involved in gas lift system analysis, troubleshooting, design, and optimization.

    The primary purpose of this API Recommended Practice (RP) is to emphasize gas lift as a system and to discuss methods used to predict its performance. Information must be gathered and models validated prior to a system design, which must precede wellbore gas lift mandrel and valve design. The subsurface and surface components of the system must be designed together to enhance the strengths of each and to minimize the constraints.

    This recommended practice bridges and enhances the general information from the API Gas Lift Manual (Book 6 of the Vocational Training Series) and the technical details of other API Gas Lift RPs, each of which contain information on a specific subject or part of the overall gas lift system. The gas lift system designer or operator should have and become familiar with the full set of documents from the API (American Petroleum Institute), GPSA (Gas Processors Suppliers Association), and ISO (International Standards Organization) that relate to gas lift system components:

    API Gas Lift Manual (Book 6 of the Vocational Training Series)

    API Spec 11V1—Gas Lift Equipment

    API RP 11V2—Gas Lift Valve Performance Testing

    API RP 11V5—Operation, Maintenance, and Troubleshooting Gas Lift Installations

    API RP 11V6—Design of Continuous Flow Gas Lift Installations

    API RP 11V7—Repair, Testing, and Setting Gas Lift Valves

    API Spec 12GDU—Glycol-Type Gas Dehydration Units

    API Spec 12J—Oil and Gas Separators

    API Std 617—Centrifugal Compressors for General Refinery Service

    API Std 618—Reciprocating Compressors for General Refinery Service

    API Manual of Petroleum Measurement Standards (MPMS)—Chapter 5, Metering; Chapter 14, Natural Gas Fluids Measurement

    GPSA—Engineering Data Book

    ISO 17078—Gas Lift Equipment Specifications


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/49a60e5e-9a91-4791-b55e-ed37dfbfc38b.htm 01-Sep-03
    API RP 11V8 1ST ED (R 2015) Recommended Practice for Gas Lift System Design and Performance Prediction; September 2003; Reaffirmed, March 2015 This section provides a broad overview of the various components of a gas lift system and how these components interact with one another.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fbfacbe3-c82c-446e-893e-e070609b269e.htm 01-Mar-15
    API RP 13B-1 1ST ED (S1) (S2) Recommended Practice Standard Procedure for Field Testing Water-Based Drilling Fluids; First Edition a. This recommended practice is under the jurisdiction of the API Committee on Standardization of Drilling Fluid Materials.

    b. The purpose of this recommended practice is to provide standard procedures for the testing of water-based drilling fluids. It is not a detailed manual on mud control procedures. It should be remembered that the agitation history and temperature of testing have a profound effect on mud properties.

    c. This recommended practice is organized to follow the tests as listed on the API Drilling Mud Report form (API RP 13G, Second Edition, May 1982). Additional tests are given in the Appendix of this recommended practice.

    d. Metric “SI” unit equivalents have been included in this publication in parentheses following the U.S. customary units.

    e. Additional publications under jurisdiction of this committee: Spec 13A, Specification for Drilling Fluid

    Materials, covers specifications and test procedures for barite, hematite, bentonite, nontreated bentonite, attapulgite, and sepiolite, starch, technical-grade low viscosity CMC, technical-grade high viscosity CMC, and OCMA grade bentonite.

    RP 13B-2 Recommended Practice Standard Procedure for Field Testing Oil-Based Drilling Fluids

    Bul 13C Bulletin on Drilling Fluids Processing Equipment

    Bul 13D Bulletin on the Rheology of Oil Well Drilling Fluids

    RP 13E Recommended Practice for Shale Shaker Screen Cloth Designation

    RP 13G Recommended Practice for Drilling Mud Report Form

    RP 13I Recommended Practice for Laboratory Testing of Drilling Fluids

    RP 13J Recommended Practice for Testing Heavy Brines

    RP 13K Recommended Practice for Chemical Analysis of Barite


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/2a61fab0-a037-4885-ac76-4719a84a37ad.htm 01-Jun-90
    API RP 13B-1 5TH ED (2019) Field Testing Water-based Drilling Fluids; Fifth Edition This recommended practice provides standard procedures for determining the following characteristics of water-based drilling fluids:

    a) drilling fluid density (mud weight);

    b) viscosity and gel strength;

    c) filtration;

    d) water, oil, and solids contents;

    e) sand content;

    f) methylene blue capacity;

    g) pH;

    h) alkalinity and lime content;

    i) chloride content;

    j) total hardness as calcium;

    k) low-gravity solids and weighting material concentrations.

    Annexes A through K provide additional test methods that may be used for:

    — chemical analysis for calcium, magnesium, calcium sulfate, sulfide, carbonate, and potassium;

    — determination of shear strength;

    — determination of resistivity;

    — removal of air;

    — drill-pipe corrosion monitoring;

    — sampling, inspection, and rejection;

    — rig-site sampling;

    — calibration and verification of glassware, thermometers, timers, viscometers, retort cup, and drilling fluid balances;

    — permeability plugging testing at high temperature and high pressure for two types of equipment;

    — Sag testing.



    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/44fe1118-3d25-446b-93e1-8cf1e5075f48.htm 01-May-19
    API RP 13B-2 3RD ED (1998) Recommended Practice Standard Procedure for Field Testing Oil-Based Drilling Fluids; Third Edition The purpose of this recommended practice is to provide standard procedures for the testing of oil-based drilling fluids. It is not a detailed manual on mud control procedures. It should be remembered that the agitation history and temperature of testing have a profound effect on mud properties.

    This recommended practice is organized to follow the tests as listed on the API Drilling Mud Report form (API RP 13G, Third Edition, February 1992). Additional tests are given in the Appendix of this recommended practice.

    Metric “SI” unit equivalents have been included in this publication in parentheses following the U.S. customary units.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/53323d73-b10f-483d-8bd7-bb5a249c4b0d.htm 01-Feb-98
    API RP 13B-2 4TH ED (2005) Recommended Practice for Field Testing of Oil-Based Drilling Fluids; Fourth Edition This Recommended Practice provides standard procedures for determining the following characteristics of oil-based drilling fluids: a) drilling fluid density (mud weight); b) viscosity and gel strength; c) filtration; d) oil, water and solids contents; e) alkalinity, chloride content and calcium content; f) electrical stability; g) lime and calcium contents, calcium chloride and sodium chloride contents; h) low-gravity solids and weighting material contents. Annexes A, B, C, D, H, I, K and L provide additional test methods that may optionally be used for the determination of i) shear strength, j) oil and water contents from cuttings, k) drilling fluid activity, l) aniline point, m) cuttings activity, n) active sulfides. o) PPA test method for cells with set screws. p) PPA test method for cells with screw-on caps. Annexes F, G and J provide procedures that may optionally be used for q) sampling, inspection and rejection, r) rig-site sampling, s) calibration and verification of glassware, thermometers, viscometers, retort kit cups and drilling fluid balances. Annex E provides examples of calculations for t) lime, salinity and solids content. Annex M contains an example of a drilling fluid report form.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/4bd58f11-d12e-4d5f-b7be-0956bf8e33e9.htm 01-Mar-05
    API RP 13B-2 4TH ED (R 2010) Recommended Practice for Field Testing of Oil-Based Drilling Fluids; Fourth Edition; Reaffirmed, October 2010 This Recommended Practice provides standard procedures for determining the following characteristics of oil-based drilling fluids: a) drilling fluid density (mud weight); b) viscosity and gel strength; c) filtration; d) oil, water and solids contents; e) alkalinity, chloride content and calcium content; f) electrical stability; g) lime and calcium contents, calcium chloride and sodium chloride contents; h) low-gravity solids and weighting material contents. Annexes A, B, C, D, H, I, K and L provide additional test methods that may optionally be used for the determination of i) shear strength, j) oil and water contents from cuttings, k) drilling fluid activity, l) aniline point, m) cuttings activity, n) active sulfides. o) PPA test method for cells with set screws. p) PPA test method for cells with screw-on caps. Annexes F, G and J provide procedures that may optionally be used for q) sampling, inspection and rejection, r) rig-site sampling, s) calibration and verification of glassware, thermometers, viscometers, retort kit cups and drilling fluid balances. Annex E provides examples of calculations for t) lime, salinity and solids content. Annex M contains an example of a drilling fluid report form.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f01f5625-9f3a-4393-8b67-e94410a7a885.htm 01-Mar-05
    API RP 13B-2 5TH ED (2014) Recommended Practice for Field Testing Oil-Based Drilling Fluids; Fifth Edition This recommended practice provides standard procedures for determining the following characteristics of oil-based drilling fluids:

    a) drilling fluid density (mud weight);

    b) viscosity and gel strength;

    c) filtration;

    d) oil, water, and solids concentrations;

    e) alkalinity, chloride concentration, and calcium concentration;

    f) electrical stability;

    g) lime and calcium concentrations, calcium chloride, and sodium chloride concentrations;

    h) low-gravity solids and weighting material concentrations.

    The annexes provide additional test methods or examples that can optionally be used for the determination of:

    — shear strength (Annex A);

    — oil and water concentrations from cuttings (Annex B);

    — drilling fluid activity (Annex C);

    — aniline point (Annex D);

    — lime, salinity, and solids concentration (Annex E);

    — sampling, inspection and rejection (Annex F);

    — rig-site sampling (Annex G);

    — cuttings activity (Annex H);

    — active sulfide (Annex I);

    — calibration and verification of glassware, thermometers, viscometers, retort kit cups, and drilling fluid balances (Annex J);

    — high-temperature/high-pressure filtration using the permeability-plugging apparatus (PPA) (Annex K);

    — elastomer compatibility (Annex L);

    — sand content of oil-based fluid (Annex M);

    — identification and monitoring of weight-material sag (Annex N);

    — oil-based drilling fluid test report form (Annex O).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a18088cb-e40f-4e85-afd3-a3e04b8ee504.htm 01-Apr-14
    API RP 13B-2 5TH ED (E1) Recommended Practice for Field Testing Oil-Based Drilling Fluids; Fifth Edition This recommended practice provides standard procedures for determining the following characteristics of oil-based drilling fluids:

    a) drilling fluid density (mud weight);

    b) viscosity and gel strength;

    c) filtration;

    d) oil, water, and solids concentrations;

    e) alkalinity, chloride concentration, and calcium concentration;

    f) electrical stability;

    g) lime and calcium concentrations, calcium chloride, and sodium chloride concentrations;

    h) low-gravity solids and weighting material concentrations.

    The annexes provide additional test methods or examples that can optionally be used for the determination of:

    — shear strength (Annex A);

    — oil and water concentrations from cuttings (Annex B);

    — drilling fluid activity (Annex C);

    — aniline point (Annex D);

    — lime, salinity, and solids concentration (Annex E);

    — sampling, inspection and rejection (Annex F);

    — rig-site sampling (Annex G);

    — cuttings activity (Annex H);

    — active sulfide (Annex I);

    — calibration and verification of glassware, thermometers, viscometers, retort kit cups, and drilling fluid balances (Annex J);

    — high-temperature/high-pressure filtration using the permeability-plugging apparatus (PPA) (Annex K);

    — elastomer compatibility (Annex L);

    — sand content of oil-based fluid (Annex M);

    — identification and monitoring of weight-material sag (Annex N);

    — oil-based drilling fluid test report form (Annex O).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/eccbf03b-fedf-4a8d-9308-38baf827beca.htm 01-Apr-14
    API RP 13B-2 5TH ED (E1) (E2) Recommended Practice for Field Testing Oil-Based Drilling Fluids; Fifth Edition This recommended practice provides standard procedures for determining the following characteristics of oil-based drilling fluids:

    a) drilling fluid density (mud weight);

    b) viscosity and gel strength;

    c) filtration;

    d) oil, water, and solids concentrations;

    e) alkalinity, chloride concentration, and calcium concentration;

    f) electrical stability;

    g) lime and calcium concentrations, calcium chloride, and sodium chloride concentrations;

    h) low-gravity solids and weighting material concentrations.

    The annexes provide additional test methods or examples that can optionally be used for the determination of:

    — shear strength (Annex A);

    — oil and water concentrations from cuttings (Annex B);

    — drilling fluid activity (Annex C);

    — aniline point (Annex D);

    — lime, salinity, and solids concentration (Annex E);

    — sampling, inspection and rejection (Annex F);

    — rig-site sampling (Annex G);

    — cuttings activity (Annex H);

    — active sulfide (Annex I);

    — calibration and verification of glassware, thermometers, viscometers, retort kit cups, and drilling fluid balances (Annex J);

    — high-temperature/high-pressure filtration using the permeability-plugging apparatus (PPA) (Annex K);

    — elastomer compatibility (Annex L);

    — sand content of oil-based fluid (Annex M);

    — identification and monitoring of weight-material sag (Annex N);

    — oil-based drilling fluid test report form (Annex O).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0f879290-25a0-4de3-959a-01ecd26318b3.htm 01-Apr-14
    API RP 13B-2 5TH ED (E1) (E2) (A1) Recommended Practice for Field Testing Oil-Based Drilling Fluids; Fifth Edition This recommended practice provides standard procedures for determining the following characteristics of oil-based drilling fluids:

    a) drilling fluid density (mud weight);

    b) viscosity and gel strength;

    c) filtration;

    d) oil, water, and solids concentrations;

    e) alkalinity, chloride concentration, and calcium concentration;

    f) electrical stability;

    g) lime and calcium concentrations, calcium chloride, and sodium chloride concentrations;

    h) low-gravity solids and weighting material concentrations.

    The annexes provide additional test methods or examples that can optionally be used for the determination of:

    — shear strength (Annex A);

    — oil and water concentrations from cuttings (Annex B);

    — drilling fluid activity (Annex C);

    — aniline point (Annex D);

    — lime, salinity, and solids concentration (Annex E);

    — sampling, inspection and rejection (Annex F);

    — rig-site sampling (Annex G);

    — cuttings activity (Annex H);

    — active sulfide (Annex I);

    — calibration and verification of glassware, thermometers, viscometers, retort kit cups, and drilling fluid balances (Annex J);

    — high-temperature/high-pressure filtration using the permeability-plugging apparatus (PPA) (Annex K);

    — elastomer compatibility (Annex L);

    — sand content of oil-based fluid (Annex M);

    — identification and monitoring of weight-material sag (Annex N);

    — oil-based drilling fluid test report form (Annex O).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3df74a92-02d2-4165-b25d-d7a39c0885f4.htm 01-Apr-14
    API RP 13C 5TH ED (2014) Recommended Practice on Drilling Fluid Processing Systems Evaluation; Fifth Edition This standard specifies a standard procedure for assessing and modifying the performance of solids control equipment systems commonly used in the field in petroleum and natural gas drilling fluids processing.

    The procedure described in this standard is not intended for the comparison of similar types of individual pieces of equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e89a0f70-b3b7-4589-aadc-cc032d8f1d75.htm 01-Oct-14
    API RP 13D 6TH ED (2010) Rheology and Hydraulics of Oil-Well Fluids; Sixth Edition 1.1 The objective of this Recommended Practice (RP) is to provide a basic understanding of and guidance about drilling fluid rheology and hydraulics, and their application to drilling operations.

    1.2 The target audience for this RP covers both the office and wellsite engineer. The complexity of the equations used is such that a competent engineer can use a simple spreadsheet program to conduct the analyses. Given that the equations used herein are constrained by the spreadsheet limitation, more advanced numerical solutions containing multiple subroutines and macros are not offered. This limitation does not mean that only the results given by the spreadsheet methods are valid engineering solutions.

    1.3 Rheology is the study of the deformation and flow of matter. Drilling fluid hydraulics pertains to both laminar and turbulent flow regimes. The methods for the calculations used herein take into account the effects of temperature and pressure on the rheology and density of the drilling fluid.

    1.4 For this RP, rheology is the study of flow characteristics of a drilling fluid and how these characteristics affect movement of the fluid. Specific measurements are made on a fluid to determine rheological parameters under a variety of conditions. From this information the circulating system can be designed or evaluated regarding how it will accomplish certain desired objectives.

    1.5 The purpose for updating the existing RP, last published in May 2003, is to make the work more applicable to the complex wells that are now commonly drilled. These include: High-Temperature/High-Pressure (HTHP), Extended-Reach Drilling (ERD), and High-Angle Wells (HAW). Drilling fluid rheology is important in the following determinations:

    a) calculating frictional pressure losses in pipes and annuli,

    b) determining equivalent circulating density of the drilling fluid under downhole conditions,

    c) determining flow regimes in the annulus,

    d) estimating hole-cleaning efficiency,

    e) estimating swab/surge pressures,

    f) optimizing the drilling fluid circulating system for improved drilling efficiency.

    1.6 The discussion of rheology in this RP is limited to single-phase liquid flow. Some commonly used concepts pertinent to rheology and flow are presented. Mathematical models relating shear stress to shear rate and formulas for estimating pressure losses, equivalent circulating densities and hole cleaning are included.

    1.7 The conventional U.S. Customary (USC) unit system is used in this RP.

    1.8 Conversion factors and examples are included for all calculations so that USC units can be readily converted to SI units. Where units are not specified, as in the development of equations, any consistent system of units may be used.

    1.9 The concepts of viscosity, shear stress, and shear rate are very important in understanding the flow characteristics of a fluid. The measurement of these properties allows a mathematical description of circulating fluid flow. The rheological properties of a drilling fluid directly affect its flow characteristics and all hydraulic calculations. They must be controlled for the fluid to perform its various functions.

    1.10 This revised document includes some example calculations to illustrate how the equations contained within the document can be used to model a hypothetical well. Due to space constraints, it has not been possible to include a step-by-step procedure for every case. However, the final results should serve as a benchmark if the user wishes to replicate the given cases.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/5294ed1a-05df-4c01-a668-1eac74cafbbe.htm 01-May-10
    API RP 13D 7TH ED (2017) Rheology and Hydraulics of Oil-well Drilling Fluids; Seventh Edition 1.1 The objective of this recommended practice (RP) is to provide a basic understanding of and guidance about drilling fluid rheology and hydraulics to assist with drilling wells of various complexities, including high-temperature/high-pressure (HTHP), extended-reach drilling (ERD), and highly directional wells.

    1.2 Office and wellsite engineers are the target audience for this document. The complexity of the equations provided is such that a competent engineer can use simple spreadsheet programs to conduct analyses. Given that the equations used herein are constrained by this spreadsheet limitation, more advanced numerical solutions containing multiple subroutines and macros are not offered. This limitation does not suggest that only the results given by the spreadsheet methods are valid engineering solutions.

    1.3 Rheology is the study of the deformation and flow of matter. For this document, rheology is the study of the flow characteristics of drilling fluids and how these characteristics affect movement of the fluids. The discussion of rheology in this document is limited to single-phase liquid flow.

    1.4 Rheological properties directly affect flow characteristics and hydraulic behavior. Properties must be controlled for drilling fluids to perform their various functions. Certain properties are measured at the wellsite for monitoring and treatment and in the laboratory for development of new additives and systems, formulation for specific applications, and diagnosis of special problems.

    1.5 Measurement of rheological properties also makes possible mathematical descriptions of circulating fluid flow important for the following hydraulics-related determinations:

    a) calculating frictional pressure losses in pipes and annuli,

    b) determining equivalent circulating density (ECD) of the drilling fluid under downhole conditions,

    c) determining flow regimes,

    d) estimating hole-cleaning efficiency,

    e) estimating swab/surge pressures, and

    f) optimizing the drilling fluid circulating system to improve drilling efficiency.

    1.6 The concepts of viscosity, shear stress, and shear rate are important in understanding the flow characteristics of fluids. Specific measurements are made on fluids to determine rheological parameters under a variety of conditions. From this information, the circulating system can be designed and evaluated to accomplish desired objectives.

    1.7 Drilling fluid hydraulics involves hydrostatic pressures, frictional pressure losses, carrying capacity, swab/surge pressures, and equivalent static and circulating densities, among others. Mathematical models relating shear stress to shear rate and formulas for estimating drilling fluid hydraulics are included. Calculation methods used herein consider the effects of temperature and pressure on drilling fluid rheology and density.

    1.8 The U.S. customary (USC) unit system is used in this RP. However, any consistent system of units may be used where so indicated, as in the development of equations in Section 4. The term “pressure” means “gauge pressure” unless otherwise noted. NOTE The term “consistent units” refers to a set of units that does not require an extra conversion factor to complete a calculation. In consistent International System of units (SI unit), time is expressed in seconds (s), length in meters (m), mass in kilograms (kg), force in newtons (N), temperature in degrees Celsius (°C), and absolute temperature in kelvins (K).In USC units , time is expressed in seconds (s), length in feet (ft), mass in pound mass (lbm), force in pound force (lbf), temperature in degrees Fahrenheit (°F), and absolute temperature in degrees Rankine (°R).

    1.9 Factors included in Section 3, Table 2 permit conversions of USC units to SI units or SI units to USC units.

    1.10 Annexes A through F contain example calculations to illustrate how equations contained within the document can be used to model a sample well. Step-by-step procedures are not included for every case; however, final results serve as benchmarks to replicate given cases.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a17dfa32-d4d1-49ac-b326-d2decb61f637.htm 01-Sep-17
    API RP 13J 5TH ED (2014) Testing of Heavy Brines; Fifth Edition API 13J covers the physical properties, potential contaminants, and test procedures for heavy brine fluids manufactured for use in oil and gas well drilling, completion, fracturing, and workover fluids.

    API 13J provides methods for assessing the performance and physical characteristics of heavy brines for use in field operations. It includes procedures for evaluating the density or specific gravity, the clarity or amount of particulate matter carried in the brines, the crystallization point or the temperature (both ambient and under pressure) at which the brines make the transition between liquid and solid, the pH, and iron contamination.

    It also contains a discussion of gas hydrate formation and mitigation, brine viscosity, corrosion testing, buffering capacity, and a standardized reporting form (see Figure A.1).

    API 13J is intended for the use of manufacturers, service companies, and end users of heavy brines.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/542d36f4-a12b-4e2e-a3b3-899fa845212c.htm 01-Oct-14
    API RP 13K 3RD ED (2011) Recommended Practice for Chemical Analysis of Barite; Third Edition 1.1 Barite is used to increase the density of oil well drilling fluids. It is a mined product that can contain significant quantities of minerals other than barium sulfate, which is its main component.

    1.2 A list of some minerals commonly associated with barite ores is given in Table 1 with the chemical formulas, mineralogical names, and the densities of the mineral grains.

    1.3 The performance of barite in a drilling fluid is related in part to the percentage and type of non-barite minerals distributed in the barite ore. Some of these minerals have little or no effect on drilling fluid properties, but others can degrade these properties and even be harmful to rig personnel.

    1.4 It is the objective of this publication to provide a comprehensive, detailed description of the chemical analytical procedures for quantitatively determining the mineral and chemical constituents of barite. These procedures are quite elaborate and will normally be carried out in a well-equipped laboratory.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5c5f801e-9259-410b-be0b-c50151dcdde5.htm 01-May-11
    API RP 13K 3RD ED (R 2016) Recommended Practice for Chemical Analysis of Barite; Third Edition; Reaffirmed, May 2016 1.1 Barite is used to increase the density of oil well drilling fluids. It is a mined product that can contain significant quantities of minerals other than barium sulfate, which is its main component.

    1.2 A list of some minerals commonly associated with barite ores is given in Table 1 with the chemical formulas, mineralogical names, and the densities of the mineral grains.

    1.3 The performance of barite in a drilling fluid is related in part to the percentage and type of non-barite minerals distributed in the barite ore. Some of these minerals have little or no effect on drilling fluid properties, but others can degrade these properties and even be harmful to rig personnel.

    1.4 It is the objective of this publication to provide a comprehensive, detailed description of the chemical analytical procedures for quantitatively determining the mineral and chemical constituents of barite. These procedures are quite elaborate and will normally be carried out in a well-equipped laboratory.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/4e199095-ee93-4f0c-a61a-b53b2506884f.htm 01-May-11
    API RP 13L 1ST ED (2003) Recommended Practice for Training and Qualification of Drilling Fluid Technologists; First Edition This standard is a written summary of basic training and knowledge that an employee or contractor shall possess to be identified as a drilling fluids technologist. Levels of understanding have been generally outlined, but not totally defined.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/9c1e718f-571d-4eec-85cd-c059e62dfee5.htm 01-Feb-03
    API RP 13L 1ST ED (R 2010) Recommended Practice for Training and Qualification of Drilling Fluid Technologists; First Edition; Reaffirmed, October 2010 This standard is a written summary of basic training and knowledge that an employee or contractor shall possess to be identified as a drilling fluids technologist. Levels of understanding have been generally outlined, but not totally defined.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/3b9f7a53-9195-45b1-b60a-11e88c585b77.htm 01-Feb-03
    API RP 13L 2ND ED (2017) Recommended Practice for Training and Qualification of Drilling Fluid Technologists; Second Edition This standard is written in two parts. The first part is a summary of basic training and knowledge that an employee or contractor shall possess in order to be identified as a rig site drilling fluids technologist or rig site drilling fluids engineer. The first part covers basic skills as would be taught in an entry-level fluids school program. The second part covers a set of advanced skills that will be required in order to support complex wells at the rig site. Levels of understanding for both core and advanced skills have been generally outlined but not totally defined.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/139e1bd3-09e3-4c69-88f4-08c1b3ae57eb.htm 01-Nov-17
    API RP 14B 6TH ED (2015) Design, Installation, Repair and Operation of Subsurface Safety Valve Systems; Fifth Edition; Reaffirmed, July 2012 This International Standard establishes requirements and provides guidelines for configuration, installation, test, operation and documentation of subsurface safety valve (SSSV) systems. In addition, this International Standard establishes requirements and provides guidelines for selection, handling, redress and documentation of SSSV downhole production equipment.

    This International Standard is not applicable to repair activities.

    NOTE: ISO 10432 provides requirements for SSSV equipment repair.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a1711f10-0121-4c12-936c-471c97a19f93.htm 01-Sep-15
    API RP 14C 7TH ED (R 2007) Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms; Seventh Edition; Reaffirmed, March 2007 This document presents recommendations for designing,

    installing, and testing a basic surface safety system on an offshore production platform. The basic concepts of a platform safety system are discussed and protection methods and requirements of the system are outlined.

    This recommended practice illustrates how system analysis methods can be used to determine safety requirements to protect any process component. Actual analyses of the principal components are developed in such a manner that the requirements determined will be applicable whenever the component is used in the process. The safety requirements of the individual process components may then be integrated into a complete platform safety system. The analysis procedures include a method to document and verify system integrity. A uniform method of identifying and symbolizing safety devices is presented and the analysis method is exemplified by a sample process system.

    In addition to the basic surface safety system, this recommended practice covers ancillary systems such as pneumatic supply and liquid containment. Procedures for testing common safety devices are presented with recommendations for test data and acceptable test tolerances.

    This recommended practice emphasizes pneumatic systems since they are the most commonly used; however, the same principles and procedures are applicable to hydraulic and electrical systems and to systems incorporating two or more control media. Instrumentation logic circuits are not discussed since these should be left to the discretion of the designer as long as the recommended safety functions are accomplished. Rotating machinery is considered in this recommended practice as a unitized process component as it interfaces with the platform safety system. When rotating machinery (such as a pump or compressor) installed as a unit consists of several process components, each component can be analyzed as prescribed in this recommended practice.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/409e1b72-b170-4bfc-82d3-6c5d6db1b91b.htm 01-Mar-01
    API RP 14C 8TH ED (2017) Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms; Eighth Edition This document presents recommendations for designing,

    installing, and testing a basic surface safety system on an offshore production platform. The basic concepts of a platform safety system are discussed and protection methods and requirements of the system are outlined.

    This recommended practice illustrates how system analysis methods can be used to determine safety requirements to protect any process component. Actual analyses of the principal components are developed in such a manner that the requirements determined will be applicable whenever the component is used in the process. The safety requirements of the individual process components may then be integrated into a complete platform safety system. The analysis procedures include a method to document and verify system integrity. A uniform method of identifying and symbolizing safety devices is presented and the analysis method is exemplified by a sample process system.

    In addition to the basic surface safety system, this recommended practice covers ancillary systems such as pneumatic supply and liquid containment. Procedures for testing common safety devices are presented with recommendations for test data and acceptable test tolerances.

    This recommended practice emphasizes pneumatic systems since they are the most commonly used; however, the same principles and procedures are applicable to hydraulic and electrical systems and to systems incorporating two or more control media. Instrumentation logic circuits are not discussed since these should be left to the discretion of the designer as long as the recommended safety functions are accomplished. Rotating machinery is considered in this recommended practice as a unitized process component as it interfaces with the platform safety system. When rotating machinery (such as a pump or compressor) installed as a unit consists of several process components, each component can be analyzed as prescribed in this recommended practice.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/352a96c2-447c-4009-9b67-89160844c158.htm 01-Feb-17
    API RP 14C 8TH ED (E1) Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms; Eighth Edition This document presents recommendations for designing,

    installing, and testing a basic surface safety system on an offshore production platform. The basic concepts of a platform safety system are discussed and protection methods and requirements of the system are outlined.

    This recommended practice illustrates how system analysis methods can be used to determine safety requirements to protect any process component. Actual analyses of the principal components are developed in such a manner that the requirements determined will be applicable whenever the component is used in the process. The safety requirements of the individual process components may then be integrated into a complete platform safety system. The analysis procedures include a method to document and verify system integrity. A uniform method of identifying and symbolizing safety devices is presented and the analysis method is exemplified by a sample process system.

    In addition to the basic surface safety system, this recommended practice covers ancillary systems such as pneumatic supply and liquid containment. Procedures for testing common safety devices are presented with recommendations for test data and acceptable test tolerances.

    This recommended practice emphasizes pneumatic systems since they are the most commonly used; however, the same principles and procedures are applicable to hydraulic and electrical systems and to systems incorporating two or more control media. Instrumentation logic circuits are not discussed since these should be left to the discretion of the designer as long as the recommended safety functions are accomplished. Rotating machinery is considered in this recommended practice as a unitized process component as it interfaces with the platform safety system. When rotating machinery (such as a pump or compressor) installed as a unit consists of several process components, each component can be analyzed as prescribed in this recommended practice.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fb2078d9-b1e6-4ec8-bb7d-11acb7fac6a4.htm 01-Feb-17
    API RP 14E 5TH ED (R 2007) Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems; Fifth Edition; Reaffirmed, March 2007 This document recommends minimum requirements and guidelines for the design and installation of new piping systems on production platforms located offshore. The maximum design pressure within the scope of this document is 10,000 psig and the temperature range is -20ºF to 650ºF. For applications outside these pressures and temperatures. special consideration should be given to material properties (ductility, carbon migration, etc.). The recommended practices presented are based on years of experience in developing oil and gas leases. Practically all of the offshore experience has been in hydrocarbon service free of hydrogen sulfide. However, recommendations based on extensive experience onshore are included for some aspects of hydrocarbon service containing hydrogen sulfide.

    a This document contains both general and specific information on surface facility piping systems not specified in. API Specification 6A. Sections 2, 3 and 4 contain general information concerning the design and application of pipe, valves, and fittings for typical processes. Sections 6 and 7 contain general information concerning installation, quality control, and items related to piping systems, e.g.; insulation, etc. for typical processes. Section 5 contains specific information concerning the design of particular piping systems including any deviations from the recommendations covered in the general sections.

    b. Carbon steel materials are suitable for the majority of the piping systems on production platforms. At least one carbon steel material recommendation is included for most applications. Other materials that may be suitable for platform piping systems have not been included because they are not generally used. The following should be considered when selecting materials other than those detailed in this RP.

    (1) Type of service.

    (2) Compatibility with other materials.

    (3) Ductility.

    (4) Need for special welding procedures.

    (5) Need for special inspection, tests, or quality control.

    (6) Possible misapplication in the field.

    (7) Corrosion/erosion caused by internal fluids and/or marine environments.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f29826ee-c347-42a3-a6c8-a18f11fad5ca.htm 01-Oct-91
    API RP 14E 5TH ED (R 2013) Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems; Fifth Edition; Reaffirmed, January 2013 This document recommends minimum

    requirements and guidelines for the design and installation of new piping systems on production platforms located offshore. The maximum design pressure within the scope of this document is 10,000 psig and the temperature range is -20’F to 650’F. For applications outside these pressures and temperatures. special consideration should be given to material properties (ductility, carbon migration, etc.). The recommended practices presented are based on years of experience in developing oil and gas leases. Practically all of the offshore experience has been in hydrocarbon service free of hydrogen sulfide. However, recommendations based on extensive experience onshore are included for some aspects of hydrocarbon service containing hydrogen sulfide.

    a This document contains both general and specific information on surface facility piping systems not specified in. API Specification 6A. Sections 2, 3 and 4 contain general information concerning the design and application of pipe, valves, and fittings for typical processes. Sections 6 and 7 contain general information concerning installation, quality control, and items related to piping systems, e.g., insulation, etc. for typical processes. Section 5 contains specific information concerning the design of particular piping systems including any deviations from the recommendations covered in the general sections.

    b. Carbon steel materials are suitable for the majority of the piping systems on production platforms. At least one carbon steel material recommendation is included for most applications. Other materials that may be suitable for platform piping systems have not been included because they are not generally used. The following should be considered when selecting materials other than those detailed in this RP.

    (1) Type of service.

    (2) Compatibility with other materials.

    (3) Ductility.

    (4) Need for special welding procedures.

    (5) Need for special inspection, tests, or quality control.

    (6) Possible misapplication in the field.

    (7) Corrosion/erosion caused by internal fluids and/or marine environments.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/668e151e-9a8d-47ff-9616-55e7d8d7e632.htm 01-Oct-91
    API RP 14E 5TH ED (R 2019) Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems; Fifth Edition; Reaffirmed, September 2019 1.1 Scope

    1.1 Scope. This document recommends minimum requirements and guidelines for the design and installation of new piping systems on production platforms located offshore. The maximum design pressure within the scope of this document is 10,000 psig and the temperature range is -20’F to 650’F. For applications outside these pressures and temperatures. special consideration should be given to material properties (ductility, carbon migration, etc.). The recommended practices presented are based on years of experience in developing oil and gas leases. Practically all of the offshore experience has been in hydrocarbon service free of hydrogen sulfide. However, recommendations based on extensive experience onshore are included for some aspects of hydrocarbon service containing hydrogen sulfide.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8489e5d0-bd2a-41b5-8949-20707f8a9fdb.htm 01-Oct-91
    API RP 14F 5TH ED (2008) Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class 1, Division 1 and Division 2 Locations; Fifth Edition 1.1.1 This document recommends minimum requirements and guidelines for the design, installation, and maintenance of electrical systems on fixed and floating petroleum facilities located offshore. For facilities classified as Zone 0, Zone 1 or Zone 2, reference API 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 or Zone 2. These facilities include drilling, producing and pipeline transportation facilities associated with oil and gas exploration and production. This recommended practice (RP) is not applicable to Mobile Offshore Drilling Units (MODUs) without production facilities. This document is intended to bring together in one place a brief description of basic desirable electrical practices for offshore electrical systems. The recommended practices contained herein recognize that special electrical considerations exist for offshore petroleum facilities. These include:

    a) the inherent electrical shock possibility presented by the marine environment and steel decks;

    b) space limitations that require that equipment be installed in or near classified locations;

    c) the corrosive marine environment;

    d) motion and buoyancy concerns associated with floating facilities.

    1.1.2 This RP applies to both permanent and temporary electrical installations. The guidelines presented herein should provide a high level of electrical safety when used in conjunction with well-defined area classifications. This RP emphasizes safe practices for classified locations on offshore petroleum facilities but does not include guidelines for classification of areas; for guidance on the classification of areas refer to API 500 and API 505, as applicable.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/8c8c1dfb-8f32-4167-99c9-c23b7d9f309d.htm 01-Jul-08
    API RP 14F 5TH ED (R 2013) Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class 1, Division 1 and Division 2 Locations; Fifth Edition; Reaffirmed, April 2013 1.1.1 This document recommends minimum requirements and guidelines for the

    design, installation, and maintenance of electrical systems on fixed and floating petroleum facilities located offshore. For facilities classified as Zone 0, Zone 1 or Zone 2, reference API 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 or Zone 2. These facilities include drilling, producing and pipeline transportation facilities associated with oil and gas exploration and production. This recommended practice (RP) is not applicable to Mobile Offshore Drilling Units (MODUs) without production facilities. This document is intended to bring together in one place a brief description of basic desirable electrical practices for offshore electrical systems. The recommended practices contained herein recognize that special electrical considerations exist for offshore petroleum facilities. These include:

    a) the inherent electrical shock possibility presented by the marine environment and steel decks;

    b) space limitations that require that equipment be installed in or near classified locations;

    c) the corrosive marine environment;

    d) motion and buoyancy concerns associated with floating facilities.

    1.1.2 This RP applies to both permanent and temporary electrical installations. The guidelines presented herein should provide a high level of electrical safety when used in conjunction with well-defined area classifications. This RP emphasizes safe practices for classified locations on offshore petroleum facilities but does not include guidelines for classification of areas; for guidance on the classification of areas refer to API 500 and API 505, as applicable.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/2a14752e-f2f9-4537-be7a-2551f4a1267f.htm 01-Jul-08
    API RP 14F 6TH ED (2018) Recommended Practice for Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1, and Division 2 Locations; Sixth Edition 1.1 General

    1.1.1 This document recommends minimum requirements and guidelines for the design, installation, and maintenance of electrical systems on fixed and floating petroleum facilities located offshore. For facilities classified as Zone 0, Zone 1, or Zone 2, reference API RP 14FZ, Recommended Practice for Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1, and Zone 2 Locations. These facilities include drilling, producing, and pipeline transportation facilities associated with oil and gas exploration and production. This recommended practice is not applicable to mobile offshore drilling units (MODUs) without production facilities. This document is intended to bring together in one place a brief description of basic desirable electrical practices for offshore electrical systems. The recommended practices contained herein recognize that special electrical considerations exist for offshore petroleum facilities. These include the following:

    a) the inherent electrical shock possibility presented by the marine environment and steel decks;

    b) space limitations that require that equipment be installed in or near hazardous (classified) locations;

    c) the corrosive marine environment;

    d) motion and buoyancy concerns associated with floating facilities.

    1.1.2 This recommended practice applies to both permanent and temporary electrical installations. The guidelines presented herein should provide a high level of electrical safety when used in conjunction with welldefined area classifications. This recommended practice emphasizes safe practices for hazardous (classified) locations on offshore petroleum facilities but does not include guidelines for classification of areas; for guidance on the classification of areas refer to API RP 500.

    1.2 Applicability of the National Electrical Code

    Electrical systems for offshore petroleum facilities shall be designed and installed in accordance with the National Electrical Code (NEC), 2017 edition, except where specific departures are noted.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e4956aa2-e2d9-40bd-b822-ab93fe2f63b6.htm 01-Oct-18
    API RP 14FZ 1ST ED (R 2007) Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2 Locations; First Edition; Reaffirmed, March 2007 1.1.1 This document recommends minimum requirements and guidelines for the design and installation of electrical systems on fixed and floating petroleum facilities located offshore when hazardous locations are classified as Zone 0, Zone 1, or Zone 2. For facilities classified as Division 1 or Division 2, reference API RP14F, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1 and Division 2 Locations. These facilities include drilling, producing and pipeline transportation facilities associated with oil and gas exploration and production. This RP is not applicable to Mobile Offshore Drilling Units (MODUs) without production facilities. This document is intended to bring together in one place a brief description of basic desirable electrical practices for offshore electrical systems. The recommended practices contained herein recognize that special electrical considerations exist for offshore petroleum facilities. These special considerations include:

    a. The inherent electrical shock possibility presented by the marine environment and steel decks.

    b. Space limitations that require that equipment be installed in or near classified locations.

    c. The corrosive marine environment.

    d. Motion and buoyancy concerns associated with floating facilities.

    1.1.2 This RP applies to both permanent and temporary electrical installations. The guidelines presented herein should provide a high level of electrical safety when used in conjunction with well-defined area classifications. This RP emphasizes safe practices for classified locations on offshore petroleum facilities but does not include guidelines for classification of areas; for guidance on classification of areas, the reader is referred to API RP500 and API RP505, as applicable.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/dfc7639a-30e3-4512-8d00-0298c681d3e2.htm 01-Sep-01
    API RP 14FZ 2ND ED (2013) Recommended Practice for Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1, and Zone 2 Locations; Second Edition 1.1.1 This document recommends minimum requirements and guidelines for the design, installation, and maintenance of electrical systems on fixed and floating petroleum facilities located offshore. For facilities classified as Division 1 or Division 2, reference API 14F. These facilities include drilling, producing and pipeline transportation facilities associated with oil and gas exploration and production. This recommended practice (RP) is not applicable to Mobile Offshore Drilling Units (MODUs) without production facilities. This document is intended to bring together in one place a brief description of basic desirable electrical practices for offshore electrical systems. The recommended practices contained herein recognize that special electrical considerations exist for offshore petroleum facilities. These include:

    a) inherent electrical shock possibility presented by the marine environment and steel decks;

    b) space limitations that require that equipment be installed in or near hazardous (classified) locations;

    c) corrosive marine environment;

    d) motion and buoyancy concerns associated with floating facilities.

    1.1.2 This RP applies to both permanent and temporary electrical installations. The guidelines presented herein should provide a high level of electrical safety when used in conjunction with well-defined area classifications. This RP emphasizes safe practices for hazardous (classified) locations on offshore petroleum facilities but does not include guidelines for classification of areas; for guidance on the classification of areas refer to API 505.

    1.1.3 Advantages of area classification using zones are as follows.

    1.1.3.1 Often, particularly for new installations and for installations that are subject to upgrade or revision, it is advantageous to classify locations as “Zones” in accordance with Article 505 of the NEC versus “Divisions” as per Article 500. These advantages may include reduced initial capital expenditures, enhanced safety, or facilities that are more easily and more economically maintained.

    1.1.3.2 In the Zone classification system, locations classified as Division 1 in the Division classification system can now be classified and further divided into Zone 0 and Zone 1 locations. Electrical equipment suitable for Zone 1 locations is not required to be suitable for locations where flammable gases and vapors may be present continuously or for long periods of time, i.e. Zone 0 locations. Thus, the protection techniques for equipment to be installed in Zone 1 locations can be less demanding than the protection techniques for equipment to be installed in Division 1 locations. This may result in more cost effective installations or equipment that is more easily maintained.

    1.1.3.3 Due to the application of increased safety (protection Type “e”) equipment, fewer field-installed sealing fittings are required for Zone 1 and Zone 2 equipment than for Division 1 and Division 2 equipment. Fewer field-installed sealing fittings reduce the chance for installation errors, enhancing safety. Much of the equipment approved for Zone 1 and Zone 2 uses plastics (versus metals), reducing corrosion, which can result in reducing maintenance costs and enhancing safety. Also, since the most hazardous locations (Zone 0 locations) are identified, such locations can be avoided for the installation of most electrical equipment. This also can enhance safety.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/f8530d60-6dd4-4c93-8f14-2bcb7d8ed5ec.htm 01-May-13
    API RP 14G 4TH ED (2007) Recommended Practice for Fire Prevention and Control on Fixed Open-Type Offshore Production Platforms; Fourth Edition This publication presents recommendations for minimizing the likelihood of having an accidental fire, and for designing, inspecting, and maintaining fire control systems. It emphasizes the need to train personnel in fire fighting, to conduct routine drills, and to establish methods and procedures for safe evacuation. The fire control systems discussed in this publication are intended to provide an early response to incipient fires to prevent their growth. However, this discussion is not intended to preclude the application of more extensive practices to meet special situations or the substitution of other systems which will provide an equivalent or greater level of protection.

    This publication is applicable to fixed open-type offshore production platforms which are generally installed in moderate climates and which have sufficient natural ventilation to minimize the accumulation of vapors. Enclosed areas, such as quarters buildings and equipment enclosures, normally installed on this type platform, are addressed. Totally enclosed platforms installed for extreme weather conditions or other reasons are beyond the scope of this RP.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ad1c3dc6-3171-4690-b521-d77d816023f4.htm 01-Apr-07
    API RP 14G 4TH ED (R 2013) Recommended Practice for Fire Prevention and Control on Fixed Open-Type Offshore Production Platforms; Fourth Edition; Reaffirmed, January 2013 This publication presents recommendations for minimizing the likelihood of

    having an accidental fire, and for designing, inspecting, and maintaining fire control systems. It emphasizes the need to train personnel in fire fighting, to conduct routine drills, and to establish methods and procedures for safe evacuation. The fire control systems discussed in this publication are intended to provide an early response to incipient fires to prevent their growth. However, this discussion is not intended to preclude the application of more extensive practices to meet special situations or the substitution of other systems which will provide an equivalent or greater level of protection.

    This publication is applicable to fixed open-type offshore production platforms which are generally installed in moderate climates and which have sufficient natural ventilation to minimize the accumulation of vapors. Enclosed areas, such as quarters buildings and equipment enclosures, normally installed on this type platform, are addressed. Totally enclosed platforms installed for extreme weather conditions or other reasons are beyond the scope of this RP.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/b983c1d9-2004-4260-a981-eb56846450b0.htm 01-Apr-07
    API RP 14G 4TH ED (R 2019) Recommended Practice for Fire Prevention and Control on Fixed Open-type Offshore Production Platforms; Fourth Edition; Reaffirmed, September 2019 1.2 Scope

    This publication presents recommendations for minimizing the likelihood of having an accidental fire, and for designing, inspecting, and maintaining fire control systems. It emphasizes the need to train personnel in fire fighting, to conduct routine drills, and to establish methods and procedures for safe evacuation. The fire control systems discussed in this publication are intended to provide an early response to incipient fires to prevent their growth. However, this discussion is not intended to preclude the appli- cation of more extensive practices to meet special situations or the substitution of other systems which will provide an equivalent or greater level of protection.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/484c75ce-18de-40dd-8604-8a04c537881b.htm 01-Apr-07
    API RP 14H 5TH ED (2007) Recommended Practice for Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves Offshore; Fifth Edition 1.1 One of the means of assuring positive wellstrean shutoff is the use of

    the wellhead surface safety valve (SSV) or underwater safety valve (USV). It is imperative that the SSV/USV be mechanically reliable. It should therefore be operated, tested and maintained in a manner to assure continuously reliable performance.

    1.2 The purpose of this Recommended Practice (RP) is to provide guidance for inspecting, installing, operating, maintaining, and onsite repairing SSVs/USVs manufactured according to API Spec 6A (17th Edition or later), Clause 10.20 or API Spec 14D (withdrawn). Included are procedures for testing SSVs/USVs.

    1.3 This RP covers guidelines for inspecting, installing, maintaining, onsite repairing, and operating SSVs/USVs. Nothing in this RP is to be construed as a fixed rule without regard to sound engineering judgment nor is it intended to override applicable federal, state or local laws.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/c28f75ed-db54-4c62-ae1d-b811968d854a.htm 01-Aug-07
    API RP 14J 2ND ED (R 2007) Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities; Second Edition; Reaffirmed, March 2007 This document recommends minimum requirements and guidelines for the design and layout of production facilities on open-type offshore platforms, and it is intended to bring together in one place a brief description of basic hazards analysis procedures for offshore production facilities. This recommended practice discusses several procedures that could be used to perform a hazards analysis, and it presents minimum requirements for process safety information and hazards analysis that can be used for satisfying the requirements of API RP 75.

    The concepts contained herein recognize that special hazard considerations exist for offshore production facilities. As a minimum, these include:

    1. Spatial limitations that may cause potential ignition sources being installed in or near production equipment.

    2. Spatial limitations that may result in quarters being installed near production equipment, pipeline/flow line risers, fuel storage tanks, or other major fuel sources.

    3. The inherent fire hazard presented by the release of flammable liquids or vapors, whether during normal operations or as a result of any unusual or abnormal condition.

    4. The severe marine environment, including corrosion, remoteness/isolation, and weather (i.e., wind, wave and current, ice).

    5. High-temperature and high-pressure fluids, hot surfaces, and rotating equipment located in or near operating areas.

    6. The handling of hydrocarbons over water.

    7. Large inventories of hydrocarbons from wells/reservoirs and pipelines connected to or crossing a producing platform.

    8. Storage and handling of hazardous chemicals.

    9. Potential H2S releases.

    This recommended practice is directed to those permanent and temporary installations associated with routine production operations. The guidelines presented herein should provide an acceptable level of safety when used in conjunction with referenced industry codes, practices and standards.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f8b82f7a-499e-4960-a2b4-58f4b2ae2b06.htm 01-May-01
    API RP 14J 2ND ED (R 2013) Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities; Second Edition; Reaffirmed, January 2013 This document recommends minimum requirements and guidelines for the design and layout of production facilities on open-type offshore platforms, and it is intended to bring together in one place a brief description of basic hazards analysis procedures for offshore production facilities. This recommended practice discusses several procedures that could be used to perform a hazards analysis, and it presents minimum requirements for process safety information and hazards analysis that can be used for satisfying the requirements of API RP 75.

    The concepts contained herein recognize that special hazard considerations exist for offshore production facilities. As a minimum, these include:

    1. Spatial limitations that may cause potential ignition sources being installed in or near production equipment.

    2. Spatial limitations that may result in quarters being installed near production equipment, pipeline/flow line risers, fuel storage tanks, or other major fuel sources.

    3. The inherent fire hazard presented by the release of flammable liquids or vapors, whether during normal operations or as a result of any unusual or abnormal condition.

    4. The severe marine environment, including corrosion, remoteness/isolation, and weather (i.e., wind, wave and current, ice).

    5. High-temperature and high-pressure fluids, hot surfaces, and rotating equipment located in or near operating areas.

    6. The handling of hydrocarbons over water.

    7. Large inventories of hydrocarbons from wells/reservoirs and pipelines connected to or crossing a producing platform.

    8. Storage and handling of hazardous chemicals.

    9. Potential H2S releases.

    This recommended practice is directed to those permanent and temporary installations associated with routine production operations. The guidelines presented herein should provide an acceptable level of safety when used in conjunction with referenced industry codes, practices and standards.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/436d0262-515b-42c8-b265-07a21a9e8498.htm 01-May-01
    API RP 14J 2ND ED (R 2019) Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities; Second Edition; Reaffirmed, September 2019 1.2 Scope

    This document recommends minimum requirements and guidelines for the design and layout of production facilities on open-type offshore platforms, and it is intended to bring together in one place a brief description of basic hazards anal- ysis procedures for offshore production facilities. This recom- mended practice discusses several procedures that could be used to perform a hazards analysis, and it presents minimum requirements for process safety information and hazards anal- ysis that can be used for satisfying the requirements of API RP 75.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c3ba7ade-0f00-4b45-a0a9-6813fbea72b7.htm 01-May-01
    API RP 15CLT 1ST ED (2007) Recommended Practice for Composite Lined Steel Tubular Goods; First Edition This recommended practice (RP) provides guidelines for the design, manufacture, qualification and application of composite lined carbon steel downhole tubing in the handling and transport of multiphase fluids, hydrocarbon gases, hydrocarbon liquids and water. The principles outlined in this RP also apply to line pipe applications.

    Composite lined tubing typically consists of a fiber reinforced polymer liner within the steel host, providing protection of that steel host from corrosive attack. Both API and premium connections can be employed, typically using corrosion barrier rings to maintain corrosion resistance between ends of adjacent liners.

    This document contains recommendations on material selection, product qualification, and definition of safety and design factors. Quality control tests, hydrostatic tests, dimensions, material properties, physical properties, and minimum performance requirements are included.

    The RP applies to composite lined carbon steel for systems up to 10 in. (250 mm) diameter, operating at pressures up to 10,000 psi (69 MPa) and maximum temperatures of 300 °F (150 °C). The principles described in this document can easily be extended to apply to products being developed by manufacturers for application outside this range.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/b0a287ae-f76d-4516-92ff-b23c5d5508ef.htm 01-Sep-07
    API RP 15CLT 1ST ED (R 2013) Recommended Practice for Composite Lined Steel Tubular Goods; First Edition; Reaffirmed, October 2013 This recommended practice (RP) provides guidelines for the design, manufacture, qualification and application of composite lined carbon steel downhole tubing in the handling and transport of multiphase fluids, hydrocarbon gases, hydrocarbon liquids and water. The principles outlined in this RP also apply to line pipe applications.

    Composite lined tubing typically consists of a fiber reinforced polymer liner within the steel host, providing protection of that steel host from corrosive attack. Both API and premium connections can be employed, typically using corrosion barrier rings to maintain corrosion resistance between ends of adjacent liners.

    This document contains recommendations on material selection, product qualification, and definition of safety and design factors. Quality control tests, hydrostatic tests, dimensions, material properties, physical properties, and minimum performance requirements are included.

    The RP applies to composite lined carbon steel for systems up to 10 in. (250 mm) diameter, operating at pressures up to 10,000 psi (69 MPa) and maximum temperatures of 300 °F (150 °C). The principles described in this document can easily be extended to apply to products being developed by manufacturers for application outside this range.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0435e3c8-fce1-4141-8c91-1d86966bdc5b.htm 01-Sep-07
    API RP 15CLT 1ST ED (R 2018) Recommended Practice for Composite Lined Steel Tubular Goods; First Edition; Reaffirmed, October 2018 This recommended practice (RP) provides guidelines for the design, manufacture, qualification and application of composite lined carbon steel downhole tubing in the handling and transport of multiphase fluids, hydrocarbon gases, hydrocarbon liquids and water. The principles outlined in this RP also apply to line pipe applications.

    Composite lined tubing typically consists of a fiber reinforced polymer liner within the steel host, providing protection of that steel host from corrosive attack. Both API and premium connections can be employed, typically using corrosion barrier rings to maintain corrosion resistance between ends of adjacent liners.

    This document contains recommendations on material selection, product qualification, and definition of safety and design factors. Quality control tests, hydrostatic tests, dimensions, material properties, physical properties, and minimum performance requirements are included.

    The RP applies to composite lined carbon steel for systems up to 10 in. (250 mm) diameter, operating at pressures up to 10,000 psi (69 MPa) and maximum temperatures of 300 °F (150 °C). The principles described in this document can easily be extended to apply to products being developed by manufacturers for application outside this range.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fcda1d28-c09f-456c-8995-266bca737be7.htm 01-Sep-07
    API RP 15S 1ST ED (2006) Qualification of Spoolable Reinforced Plastic Line Pipe; First Edition This Recommended Practice (RP) provides guidelines for the design, manufacture, qualification and application of spoolable reinforced plastic line pipe in oilfield flowline applications, including transport of multiphase fluids, hydrocarbon gases, hydrocarbon liquids and water. Such products typically consist of a continuous plastic liner reinforced with either glass reinforced epoxy—Spoolable Composite Pipe (SCP), or aramid fibers—Reinforced Thermoplastic Pipe (RTP). They are continuous flowline systems capable of being reeled for storage, transport and installation. For offshore use, additional requirements may apply.

    This document contains recommendations on material selection, product qualification, and pressure rating. Quality control tests, hydrostatic tests, dimensions, material properties, physical properties, and minimum performance requirements are included.

    The qualification tests in the RP are designed around non-metallic reinforcements, exhibiting time dependent mechanical properties characterized by regression analysis. Metallic reinforcement is, therefore, specifically excluded.

    The RP applies typically to spoolable reinforced plastic flowline systems up to 6 in. (150 mm) diameter, pressures of up to 5000 psi (34.5 MPa) and maximum temperatures of 200°F (93°C), although the principles described in this document can be extended to apply to products outside this range.

    The RP is confined to pipe and end fittings or couplers, and does not relate to other system components. Where other system components (elbows, tees, valves etc.) are of conventional construction they will be governed by applicable codes and practices.

    The RP covers pipe systems where the pressure and thermal loading is static or cyclic, with loads resulting from typical installation methods. It does not cover systems that are subjected to other types of static or dynamic loads.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/807399a2-6280-43a2-b06f-e448764afa16.htm 01-Mar-06
    API RP 15S 1ST ED (R 2013) Qualification of Spoolable Reinforced Plastic Line Pipe; First Edition This Recommended Practice (RP) provides guidelines for the design, manufacture, qualification and application of spoolable reinforced plastic line pipe in oilfield flowline applications, including transport of multiphase fluids, hydrocarbon gases, hydrocarbon liquids and water. Such products typically consist of a continuous plastic liner reinforced with either glass reinforced epoxy—Spoolable Composite Pipe (SCP), or aramid fibers—Reinforced Thermoplastic Pipe (RTP). They are continuous flowline systems capable of being reeled for storage, transport and installation. For offshore use, additional requirements may apply.

    This document contains recommendations on material selection, product qualification, and pressure rating. Quality control tests, hydrostatic tests, dimensions, material properties, physical properties, and minimum performance requirements are included.

    The qualification tests in the RP are designed around non-metallic reinforcements, exhibiting time dependent mechanical properties characterized by regression analysis. Metallic reinforcement is, therefore, specifically excluded.

    The RP applies typically to spoolable reinforced plastic flowline systems up to 6 in. (150 mm) diameter, pressures of up to 5000 psi (34.5 MPa) and maximum temperatures of 200°F (93°C), although the principles described in this document can be extended to apply to products outside this range.

    The RP is confined to pipe and end fittings or couplers, and does not relate to other system components. Where other system components (elbows, tees, valves etc.) are of conventional construction they will be governed by applicable codes and practices.

    The RP covers pipe systems where the pressure and thermal loading is static or cyclic, with loads resulting from typical installation methods. It does not cover systems that are subjected to other types of static or dynamic loads.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/1b370878-11b7-4cb5-806d-7879373fb14b.htm 01-Mar-06
    API RP 15S 2ND ED (2016) Qualification of Spoolable Reinforced Plastic Line Pipe; Second Edition This Recommended Practice (RP) provides guidelines for the design, manufacture, qualification and application of spoolable reinforced plastic line pipe in oilfield flowline applications, including transport of multiphase fluids, hydrocarbon gases, hydrocarbon liquids and water. Such products typically consist of a continuous plastic liner reinforced with either glass reinforced epoxy—Spoolable Composite Pipe (SCP), or aramid fibers—Reinforced Thermoplastic Pipe (RTP). They are continuous flowline systems capable of being reeled for storage, transport and installation. For offshore use, additional requirements may apply. This document contains recommendations on material selection, product qualification, and pressure rating. Quality control tests, hydrostatic tests, dimensions, material properties, physical properties, and minimum performance requirements are included. The qualification tests in the RP are designed around non-metallic reinforcements, exhibiting time dependent mechanical properties characterized by regression analysis. Metallic reinforcement is, therefore, specifically excluded. The RP applies typically to spoolable reinforced plastic flowline systems up to 6 in. (150 mm) diameter, pressures of up to 5000 psi (34.5 MPa) and maximum temperatures of 200°F (93°C), although the principles described in this document can be extended to apply to products outside this range. The RP is confined to pipe and end fittings or couplers, and does not relate to other system components. Where other system components (elbows, tees, valves etc.) are of conventional construction they will be governed by applicable codes and practices. The RP covers pipe systems where the pressure and thermal loading is static or cyclic, with loads resulting from typical installation methods. It does not cover systems that are subjected to other types of static or dynamic loads.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/4b75b4f9-84e0-4ea4-b853-c9111c19e49b.htm 01-Mar-16
    API RP 15TL4 2ND ED (R 2008) Recommended Practice for Care and Use of Fiberglass Tubulars; Second Edition; Reaffirmed, May 2008 The purpose of this publication is to provide information on the transporting, handling, installing, and reconditioning of fiberglass tubulars in oilfield usage.

    Note: No provision of this Recommended Practice shall be cause for rejection of fiberglass tubulars provided the threads are in accordance with the requirements of the applicable product specification.

    Trouble-free service and maximum safety should result if this Recommended Practice is followed. Fiberglass tubulars differ in properties from metallic tubular goods and different installation techniques are required.

    Note: These recommendations are applicable to normal situations. Exceptional conditions may warrant different practices. It is not intended that these practices conflict with any regulatory code.

    It is suggested that the selection of thread compound be given careful consideration by the user bearing in mind that a satisfactory compound should possess certain properties, the major of which are (1) to lubricate the thread surfaces to facilitate joint make up and break out without galling and (2) to seal voids between mating thread surfaces and effectively prevent leakage. Thread compounds have a significant impact on the performance of tubulars, especially under combined loading conditions. The manufacturer’s recommended thread compound, which has been qualified in accord with the API product specification, should be used.

    CAUTION: The material safety data sheets for thread compounds should be read and observed. Store and dispose of containers and unused compound in accord with appropriate regulations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f1ab12e8-ac61-44ce-a894-2324ea8e1ffd.htm 01-Mar-99
    API RP 15TL4 2ND ED (R 2013) Recommended Practice for Care and Use of Fiberglass Tubulars; Second Edition; Reaffirmed, October 2013 The purpose of this publication is to provide information on the transporting, handling, installing, and reconditioning of fiberglass tubulars in oilfield usage.

    Note: No provision of this Recommended Practice shall be cause for rejection of fiberglass tubulars provided the threads are in accordance with the requirements of the applicable product specification.

    Trouble-free service and maximum safety should result if this Recommended Practice is followed. Fiberglass tubulars differ in properties from metallic tubular goods and different installation techniques are required.

    Note: These recommendations are applicable to normal situations. Exceptional conditions may warrant different practices. It is not intended that these practices conflict with any regulatory code.

    It is suggested that the selection of thread compound be given careful consideration by the user bearing in mind that a satisfactory compound should possess certain properties, the major of which are (1) to lubricate the thread surfaces to facilitate joint make up and break out without galling and (2) to seal voids between mating thread surfaces and effectively prevent leakage. Thread compounds have a significant impact on the performance of tubulars, especially under combined loading conditions. The manufacturer’s recommended thread compound, which has been qualified in accord with the API product specification, should be used.

    CAUTION: The material safety data sheets for thread compounds should be read and observed. Store and dispose of containers and unused compound in accord with appropriate regulations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/7a1acdac-c734-4a8d-a857-819a49cadea2.htm 01-Mar-99
    API RP 15TL4 2ND ED (R 2018) Recommended Practice for Care and Use of Fiberglass Tubulars; Second Edition; Reaffirmed, November 2018 The purpose of this publication is to provide information on the transporting, handling, installing, and reconditioning of fiberglass tubulars in oilfield usage.

    Note: No provision of this Recommended Practice shall be cause for rejection of fiberglass tubulars provided the threads are in accordance with the requirements of the applicable product specification.

    Trouble-free service and maximum safety should result if this Recommended Practice is followed. Fiberglass tubulars differ in properties from metallic tubular goods and different installation techniques are required.

    Note: These recommendations are applicable to normal situations. Exceptional conditions may warrant different practices. It is not intended that these practices conflict with any regulatory code.

    It is suggested that the selection of thread compound be given careful consideration by the user bearing in mind that a satisfactory compound should possess certain properties, the major of which are (1) to lubricate the thread surfaces to facilitate joint make up and break out without galling and (2) to seal voids between mating thread surfaces and effectively prevent leakage. Thread compounds have a significant impact on the performance of tubulars, especially under combined loading conditions. The manufacturer’s recommended thread compound, which has been qualified in accord with the API product specification, should be used.

    CAUTION: The material safety data sheets for thread compounds should be read and observed. Store and dispose of containers and unused compound in accord with appropriate regulations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/4e8239e5-57ee-49b5-b043-794036734637.htm 01-Mar-99
    API RP 15WT 1ST ED (2019) Operations for Layflat Hose in Oilfield Water Applications; First Edition; December 2019 This document provides guidelines and establishes recommended practices for the operation of layflat hose used for the transportation of water associated with onshore upstream oil and gas operations, to prevent damage of layflat hose and damage of layflat hose assemblies. This document covers the transportation of formation water, injection water, brackish water, fresh water, and saline. The scope of this document excludes the initial and final connections of the layflat hose to the source and receiving points.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/2e525eed-02a6-40e3-9263-24013c675330.htm 01-Dec-19
    API RP 16Q 1ST ED (R 2001) Recommended Practice for Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems; First Edition; Reaffirmed, August 2001 The marine drilling riser is best viewed as a system. Designers, contractors, and operators should be cognizant that the individual components should be designed and selected so as to suit the overall performance of that system. For the purposes of this Recommended Practice, a marine drilling riser system includes the tensioner system and all equipment between the top connection of the upper flex/ball joint and the bottom connection of the lower flex/ball joint. It specifically excludes the diverter, LMRP, BOP stack, and hydraulic connectors.

    Sections 1 through 4 of this RP are directly applicable to most floating drilling operations. For deepwater locations (exceeding 2000 feet for the purposes of this document), refer to the paragraphs in Section 5 dealing with Deepwater Drilling and Collapse. The special considerations required for Guidelineless Drilling are also addressed in Section 5. In addition, Section 5 addresses precautions when drilling in High Currents, in Cold Weather Areas, or when H2S is present.

    All riser primary load path components addressed in this RP should be consistent with the load classifications specified in API RP 2R (Design, Rating, and Testing of Marine Drilling Riser Couplings).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/2b619566-2ca0-4be7-b31c-353f11c05d0b.htm 01-Nov-93
    API RP 16Q 1ST ED (R 2010) Recommended Practice for Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems; First Edition; Reaffirmed, August 2010 The marine drilling riser is best viewed as a system. Designers, contractors, and operators should be cognizant that the individual components should be designed and selected so as to suit the overall performance of that system. For the purposes of this Recommended Practice, a marine drilling riser system includes the tensioner system and all equipment between the top connection of the upper flex/ball joint and the bottom connection of the lower flex/ball joint. It specifically excludes the diverter, LMRP, BOP stack, and hydraulic connectors.

    Sections 1 through 4 of this RP are directly applicable to most floating drilling operations. For deepwater locations (exceeding 2000 feet for the purposes of this document), refer to the paragraphs in Section 5 dealing with Deepwater Drilling and Collapse. The special considerations required for Guidelineless Drilling are also addressed in Section 5. In addition, Section 5 addresses precautions when drilling in High Currents, in Cold Weather Areas, or when H2S is present.

    All riser primary load path components addressed in this RP should be consistent with the load classifications specified in API RP 2R (Design, Rating, and Testing of Marine Drilling Riser Couplings).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/22fc1d25-5245-4e45-83cc-2c4dcc8989b2.htm 01-Nov-93
    API RP 16Q 2ND ED (2017) Design, Selection, Operation, and Maintenance of Marine Drilling Riser Systems; Second Edition API 16Q provides requirements for the design, selection, operation, and maintenance of typical marine riser systems for floating drilling operations from a mobile offshore drilling unit (MODU) with a subsea blowout preventer (BOP) stack. Its purpose is to serve as a reference for designers, for those who select system components, and for those who use and maintain this equipment. It relies on basic engineering principles and the accumulated experience of offshore operators, contractors, consultants, and manufacturers.

    Since technology is continuously advancing in this field, methods and equipment are improving and evolving. Each owner and operator is encouraged to observe the recommendations outlined herein and to supplement them with other proven technology that can result in a more cost-effective, safer, and/or more reliable performance.

    The marine drilling riser is best viewed as a system. It is necessary that designers, contractors, and operators realize that the individual components are recommended and selected in a manner suited to the overall performance of that system. For the purposes of this document, a marine drilling riser system includes the tensioner system and all equipment between the top connection of the upper flex/ball joint to the lower flex joint. However, it specifically excludes the diverter. Also, the applicability of this document is limited to operations with a subsea BOP stack.

    Sections 1 through 7 are applicable to most floating drilling operations. In addition, special situations andtopics are addressed in Section 8 dealing with deepwater drilling, cold weather environments, riser collapse, hydrogen sulfide (H2S), well testing, and managed pressure drilling (MPD). It is important that all riser primary load-path components addressed in this document be consistent with the load classifications specified in API 16R and API 16F.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0b1b7e0f-636a-4bbe-8131-40dc4e11600b.htm 01-Apr-17
    API RP 16ST 1ST ED (2009) Coiled Tubing Well Control Equipment Systems; First Edition 1.1 General

    This recommended practice (RP) addresses coiled tubing well control equipment assembly and operation as it relates to well control practices. Industry practices for performing well control operations using fluids for hydrostatic pressure balance are not addressed in this RP.

    This document covers well control equipment assembly and operation used in coiled tubing intervention and coiled tubing drilling applications performed through:

    — christmas trees constructed in accordance with API 6A and/or API 11IW,

    — a surface flow head or surface test tree constructed in accordance with API 6A,

    — drill pipe or workstrings with connections manufactured in accordance with API 7 and/or API 5CT.

    1.2 Operations Not Covered in this Document

    The following operations are not covered in the scope of this document:

    a) coiled tubing well intervention operations without the christmas tree (or surface test tree) in place,

    b) coiled tubing drilling operations without the christmas tree (or surface test tree) in place,

    c) capillary tubing (tubing less than 3/4 in. OD) well service operations,

    d) coiled tubing intervention operations within pipelines and flowlines,

    e) reverse circulation operations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c95868f3-f242-41d4-b4da-b4a678c1c9f9.htm 01-Mar-09
    API RP 16ST 1ST ED (R 2014) Coiled Tubing Well Control Equipment Systems; First Edition; December 2014 1.1 General

    This recommended practice (RP) addresses coiled tubing well control equipment assembly and operation as it relates to well control practices. Industry practices for performing well control operations using fluids for hydrostatic pressure balance are not addressed in this RP.

    This document covers well control equipment assembly and operation used in coiled tubing intervention and coiled tubing drilling applications performed through:

    — christmas trees constructed in accordance with API 6A and/or API 11IW,

    — a surface flow head or surface test tree constructed in accordance with API 6A,

    — drill pipe or workstrings with connections manufactured in accordance with API 7 and/or API 5CT.

    1.2 Operations Not Covered in this Document

    The following operations are not covered in the scope of this document:

    a) coiled tubing well intervention operations without the christmas tree (or surface test tree) in place,

    b) coiled tubing drilling operations without the christmas tree (or surface test tree) in place,

    c) capillary tubing (tubing less than 3/4 in. OD) well service operations,

    d) coiled tubing intervention operations within pipelines and flowlines,

    e) reverse circulation operations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9f84c083-04b8-4cb3-b54a-0fe4b945b6b7.htm 01-Mar-09
    API RP 17A 5TH ED (2017) Design and Operation of Subsea Production Systems—General Requirements and Recommendations; Fifth Edition http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/cbdd3a12-1bee-4f05-8b9d-1fdd7d2d467f.htm 01-May-17
    API RP 17B 5TH ED (2014) Recommended Practice for Flexible Pipe; Fifth Edition API 17B provides guidelines for the design, analysis, manufacture, testing,

    installation, and operation of flexible pipes and flexible pipe systems for onshore, subsea, and marine applications. API 17B supplements API 17J and API 17K, which specify minimum requirements for the design, material selection, manufacture, testing, marking, and packaging of unbonded and bonded flexible pipes, respectively.

    API 17B applies to flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. Both bonded and unbonded pipe types are covered. In addition, API 17B applies to flexible pipe systems, including ancillary components.

    The applications covered by API 17B are sweet and sour service production, including export and injection applications. API 17B applies to both static and dynamic flexible pipe systems, used as flowlines, risers, jumpers, downlines, and other temporary applications of flexible pipe. API 17B does cover in general terms, the use of flexible pipes for offshore loading systems. Refer also to API 17K and Bibliographic Item [54] for offshore loading systems.

    API 17B does not cover flexible pipes for use in choke and kill line or umbilical and control lines.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/58833808-f6da-4089-ae56-a2493154610f.htm 01-May-14
    API RP 17G5 1ST ED (2019) Subsea Intervention Workover Control Systems; First Edition; November 2019 1 Scope

    This document provides the requirements for the design, manufacture, and testing of intervention workover control system (IWOCS) equipment. Blowout prevention (BOP) control systems are outside the scope of this Recommended Practice and typically are not connected to the IWOCS.

    Some requirements in this document are specific to the execution of end user–defined safety functions. It is the end users’ responsibility to define the safety functions (i.e. timed sequence of events to operate a safety class device) as an input to this document. This document defines “safety class control functions” used to operate safety class devices. Annex A provides guidance on the determination of safety class control functions based on the end user–provided safety functions.

    This document identifies the IWOCS equipment typically used in a thru-blowout preventer intervention riser system (TBIRS) and an open-water intervention riser system (OWIRS); see API 17G for more details on these systems and associated components. The IWOCS equipment described in this document may be used for other system types. Table 1 lists equipment typically controlled by an IWOCS. Refer to Figure 1 and Figure 2 for example IWOCS block diagrams for both system types.

    IWOCS equipment may be configured in one of the control system architectures listed below. It is not the intent of this document to mandate the type of control system architecture used for a given application.

    The IWOCS equipment may be deployed using one of the methods listed below (see Figure 3 for typical deployment methods). It is not the intent of this document to mandate the type of deployment method used. All normal class and safety class control functions (see 3.1.8 and 3.1.12, respectively) need to conform to the requirements given within this document regardless of deployment method.

    • Dependent Riser Based Deployment Method: The dependent riser deployment method supports the umbilical’s weight by attaching it to an existing riser (e.g., drilling marine riser or open water riser). Deployment and recovery of the IWOCS using this mode is often dependent on the riser to which the IWOCS is attached.
    • Independent Riser Based Deployment Method: The independent riser deployment method supports the umbilical’s weight using a dedicated riser for the IWOCS. This dedicated riser may be a wire, cable or the umbilical itself. The independent riser deployment method may use a launch and recovery system (LARS) and sheave to overboard the umbilical during deployment and retrieval. Deployment and recovery of IWOCS using this mode is often independent of other risers on the vessel or rig.
    • ROV Based Deployment Method: The ROV based deployment method is very similar to the independent riser method; however, it uses a ROV winch, sheave, and LARS arrangement to deploy and recover the ROV and its umbilical. The ROV based deployment method may additionally use a ROV skid (i.e., belly skid) for additional functionality if required.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8a9ec642-abc9-457b-9ff7-d63f9a1cc9d4.htm 01-Nov-19
    API RP 17H 2ND ED (2013) Remotely Operated Tools and Interfaces on Subsea Production Systems; Second Edition This document provides recommendations for development and design of remotely operated subsea tools and interfaces on subsea production systems in order to maximize the potential of standardizing equipment and design principles.

    This document does not cover manned intervention, internal wellbore intervention, internal flowline inspection, tree running, and tree running equipment. However, all the related subsea remotely operated vehicle/remotely operated tool (ROV/ROT) interfaces are covered by this standard. It is applicable to the selection, design, and operation of ROTs and ROVs including ROV tooling, hereafter defined in a common term as subsea intervention systems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/7f90f3c6-f53d-455a-8980-562bce6dccab.htm 01-Jun-13
    API RP 17H 2ND ED (E1) Remotely Operated Tools and Interfaces on Subsea Production Systems; Second Edition This document provides recommendations for development and design of remotely

    operated subsea tools and interfaces on subsea production systems in order to maximize the potential of standardizing equipment and design principles.

    This document does not cover manned intervention, internal wellbore intervention, internal flowline inspection, tree running, and tree running equipment. However, all the related subsea remotely operated vehicle/remotely operated tool (ROV/ROT) interfaces are covered by this standard. It is applicable to the selection, design, and operation of ROTs and ROVs including ROV tooling, hereafter defined in a common term as subsea intervention systems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/084bf83b-f2ae-4f25-a63f-c2c52b3202b3.htm 01-Jun-13
    API RP 17H 3RD ED (2019) Remotely Operated Tools and Interfaces on Subsea Production Systems; Third Edition 1 Scope

    API Recommended Practice 17H provides recommendations for development and design of remotely operated subsea tools and interfaces on subsea production systems to maximize the potential of standardizing equipment and design principles.

    This document does not cover manned intervention, internal wellbore intervention, internal flowline inspection, tree running and tree running equipment. However, all the related subsea ROV/ROT/AUV interfaces are covered by this standard. It is applicable to the selection, design and operation of ROTs, ROVs and AUVs including ROV tooling, hereafter defined as “subsea intervention systems”.

    This Recommended Practice (RP) provides functional requirements and guidelines for ROV/ROT/AUV interfaces in subsea production fields for the petroleum and natural gas industries. It is applicable to both the selection and use of ROV/ROT/AUV interfaces related to subsea production equipment and provides guidance on design as well as the operational requirements for maximizing the potential of standardized equipment and design principles. This RP identifies the issues to be considered when designing for ROV/ROT/AUV operations to interact with (or near) subsea production systems. The framework and specifications set out enables the user (whether they may be on the ROV/ROT/AUV side or production facility side) to design the appropriate interface for a specific application. These interfaces include subsea docking, recharging, data transfer, data harvesting, and mechanical intervention.

    It is anticipated that in the future, resident ROVs/AUVs near the seabed can provide high value for oil and gas inspection, monitoring, and maintenance and repair activities. The benefits of employing ROVs/AUVs in such situations include reduced operating costs and improved safety. The guidelines established in this RP leads to efficient development and deployment of ROV/ROT/AUV systems, providing clarity for operators, contractors, and developers. Recommendations have been provided in a flexible manner to accommodate a wide variation of AUV styles and applications, while maintaining an appropriate level of interface commonality for specification.

    This document defines four major categories of hot stabs and describes the geometry to maintain compatibility across all manufacturers. The categories were first introduced in Technical Report 17TR15 which described several common or previously used hydraulic hot stab and receptacle configurations. The approach is to ensure backward compatibility of the hot stabs described in API Recommended Practice 17H, 2nd Edition and to align API RP 17H with API S53 and API 16D.

    This RP is not intended to replace sound engineering judgment as to when and where its provisions are to be used. Users need to be aware that additional or differing details may be required to meet a specific service or local legislation.

    This document is not intended to deter the development of new technology. The intention is to facilitate and complement the decision processes, and the responsible engineer is encouraged to review standard interfaces and re-use intervention tooling in the interests of minimizing life-cycle costs and increasing the use of proven interfaces.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/117850fc-0ef8-40a5-85b5-e35e376d8f4f.htm 01-Jul-19
    API RP 17L2 1ST ED (2013) Recommended Practice for Flexible Pipe Ancillary Equipment; First Edition This Recommended Practice provides guidelines for the design, materials selection, analysis, testing, manufacture, handling, transportation, installation and integrity management of flexible pipe ancillary equipment. It supplements API 17L1, which specifies minimum requirements for the design, material selection, manufacture, documentation, testing, marking and packaging of flexible pipe ancillary equipment.

    This Recommended Practice presents the current best practice for design and procurement of ancillary equipment, and gives guidance on the implementation of the specification for standard flexible pipe ancillary products. In addition, this Recommended Practice presents guidelines on the qualification of prototype products.

    The applicability relating to a specific item of ancillary equipment within this Recommended Practice is stated at the beginning of the section dedicated to that item of ancillary equipment.

    This Recommended Practice applies to the following flexible pipe ancillary equipment:

    — bend stiffeners;

    — bend restrictors;

    — bellmouths;

    — buoyancy modules and ballast modules;

    — subsea buoys;

    — tethers for subsea buoys and tether clamps;

    — riser and tether bases;

    — clamping devices;

    — piggy-back clamps;

    — repair clamps;

    — I/J-tube seals;

    — pull-in heads/installation aids;

    — connectors;

    — load-transfer devices;

    — mechanical protection;

    — fire protection.

    This document may be used for bonded flexible pipe ancillary equipment, though any requirements specific to these applications are not addressed. Where relevant, the applicability of recommendations to umbilicals is indicated in the applicability section for the ancillary equipment in question.

    This Recommended Practice does not cover flexible pipe ancillary equipment beyond the connector, with the exception of riser bases and load-transfer devices. Therefore this document does not cover turret structures or I-tubes and J-tubes, for example. In addition, it does not cover flexible pipe storage devices, for example reels.

    This Recommended Practice is intended to cover ancillary equipment made from several material types, including metallic, polymer and composite materials. It may also refer to material types for particular ancillary components that are not commonly used for such components currently, but may be adopted in the future.

    This Recommended Practice applies to ancillary equipment used in association with the flexible pipe applications listed in Section 1 of API 17J:2008; API 17K:2005 and in API 17B.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/577daaa3-c7c2-4055-b831-0b14b7463442.htm 01-Mar-13
    API RP 17N 1ST ED (2009) Recommended Practice for Subsea Production System Reliability and Technical Risk Management; First Edition The application of subsea technology in the offshore oil and gas industry

    demands large capital investments and significant operational expenditures. The value of using subsea technology depends on its production availability (see 3.17) which is a reflection of its reliability and maintainability (RM).

    This API recommended practice (RP) aims to provide operators, contractors and suppliers with guidance in the application of reliability techniques to subsea projects within their scope of work and supply only. It is applicable to:

    — standard and non-standard equipment,

    — all phases of projects from feasibility studies to operation.

    This RP does not prescribe the use of any specific equipment or limit the use of any existing installed equipment or indeed recommend any action, beyond good engineering practice, where current reliability is judged to be acceptable. It is also not intended to replace individual company processes, procedures, document nomenclature or numbering; it is a guide. However, this RP may be used to enhance existing processes, if deemed appropriate.

    Users of this RP should gain a better understanding of how to manage an appropriate level of reliability throughout the life cycle of their subsea projects. Industry wide, users should be able to:

    — recognize the trade off between up front reliability and engineering effort vs. operational maintenance effort,

    — provide better assurance of future performance of subsea systems,

    — effectively manage the risks from using novel equipment and standard equipment in novel applications,

    — schedule projects with sufficient time to address all the technical risks.

    Overall, this should lead to better understanding of technical risk and, therefore, greater confidence in economically or technically challenging developments.

    Furthermore, this RP provides the industry with a common framework and language, compatible with ISO 20815, Petroleum, petrochemical and natural gas industries—Production assurance and reliability management, for the specification and demonstration of reliability achievement between operators, contractors, and suppliers.

    Reliability is a topic which is best addressed through industry wide cooperation in terms of best practice, managing failures that do occur and the collection and analysis of performance data. This RP aims to provide a starting point for developing common understanding and cooperative progress within the subsea oil and gas industry.

    The achievement of improved subsea equipment availability requires good engineering and management processes, practices and behaviors at an organizational level to manage and minimize the potential for equipment failure.

    The focus of this RP however, is on specific activities (or tasks) that can be implemented within projects to achieve immediate and tangible improvements to system performance.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/a123e3d2-c704-4f25-b1d5-3ed7ff448800.htm 01-Mar-09
    API RP 17N 2ND ED (2017) Recommended Practice for Subsea Production System Reliability and Technical Risk Management; Second Edition The application of subsea technology in the offshore oil and gas industry

    demands large capital investments and significant operational expenditures. The value of using subsea technology depends on its production availability (see 3.17) which is a reflection of its reliability and maintainability (RM).

    This API recommended practice (RP) aims to provide operators, contractors and suppliers with guidance in the application of reliability techniques to subsea projects within their scope of work and supply only. It is applicable to:

    — standard and non-standard equipment,

    — all phases of projects from feasibility studies to operation.

    This RP does not prescribe the use of any specific equipment or limit the use of any existing installed equipment or indeed recommend any action, beyond good engineering practice, where current reliability is judged to be acceptable. It is also not intended to replace individual company processes, procedures, document nomenclature or numbering; it is a guide. However, this RP may be used to enhance existing processes, if deemed appropriate.

    Users of this RP should gain a better understanding of how to manage an appropriate level of reliability throughout the life cycle of their subsea projects. Industry wide, users should be able to:

    — recognize the trade off between up front reliability and engineering effort vs. operational maintenance effort,

    — provide better assurance of future performance of subsea systems,

    — effectively manage the risks from using novel equipment and standard equipment in novel applications,

    — schedule projects with sufficient time to address all the technical risks.

    Overall, this should lead to better understanding of technical risk and, therefore, greater confidence in economically or technically challenging developments.

    Furthermore, this RP provides the industry with a common framework and language, compatible with ISO 20815, Petroleum, petrochemical and natural gas industries—Production assurance and reliability management, for the specification and demonstration of reliability achievement between operators, contractors, and suppliers.

    Reliability is a topic which is best addressed through industry wide cooperation in terms of best practice, managing failures that do occur and the collection and analysis of performance data. This RP aims to provide a starting point for developing common understanding and cooperative progress within the subsea oil and gas industry.

    The achievement of improved subsea equipment availability requires good engineering and management processes, practices and behaviors at an organizational level to manage and minimize the potential for equipment failure.

    The focus of this RP however, is on specific activities (or tasks) that can be implemented within projects to achieve immediate and tangible improvements to system performance.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d9c928d3-a07c-42c1-9565-327372355110.htm 01-Jun-17
    API RP 17N 2ND ED (A1) Recommended Practice for Subsea Production System Reliability and Technical Risk Management; Second Edition The application of subsea technology in the offshore oil and gas industry demands large capital investments and significant operational expenditures. The value of using subsea technology depends on its production availability (see 3.17) which is a reflection of its reliability and maintainability (RM).

    This API recommended practice (RP) aims to provide operators, contractors and suppliers with guidance in the application of reliability techniques to subsea projects within their scope of work and supply only. It is applicable to:

    — standard and non-standard equipment,

    — all phases of projects from feasibility studies to operation.

    This RP does not prescribe the use of any specific equipment or limit the use of any existing installed equipment or indeed recommend any action, beyond good engineering practice, where current reliability is judged to be acceptable. It is also not intended to replace individual company processes, procedures, document nomenclature or numbering; it is a guide. However, this RP may be used to enhance existing processes, if deemed appropriate.

    Users of this RP should gain a better understanding of how to manage an appropriate level of reliability throughout the life cycle of their subsea projects. Industry wide, users should be able to:

    — recognize the trade off between up front reliability and engineering effort vs. operational maintenance effort,

    — provide better assurance of future performance of subsea systems,

    — effectively manage the risks from using novel equipment and standard equipment in novel applications,

    — schedule projects with sufficient time to address all the technical risks.

    Overall, this should lead to better understanding of technical risk and, therefore, greater confidence in economically or technically challenging developments.

    Furthermore, this RP provides the industry with a common framework and language, compatible with ISO 20815, Petroleum, petrochemical and natural gas industries—Production assurance and reliability management, for the specification and demonstration of reliability achievement between operators, contractors, and suppliers.

    Reliability is a topic which is best addressed through industry wide cooperation in terms of best practice, managing failures that do occur and the collection and analysis of performance data. This RP aims to provide a starting point for developing common understanding and cooperative progress within the subsea oil and gas industry.

    The achievement of improved subsea equipment availability requires good engineering and management processes, practices and behaviors at an organizational level to manage and minimize the potential for equipment failure.

    The focus of this RP however, is on specific activities (or tasks) that can be implemented within projects to achieve immediate and tangible improvements to system performance.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9cf77502-5d53-491a-bba9-222696aab969.htm 01-May-18
    API RP 17O 1ST ED (2009) Recommended Practice for Subsea High Integrity Pressure Protection Systems (HIPPS); First Edition This recommended practice (RP) addresses the requirements for the use of high integrity pressure protection systems (HIPPS) for subsea applications. API 14C, IEC 61508, and IEC 61511 specify the requirements for onshore, topsides, and subsea safety instrumented systems (SIS’s) and are applicable to HIPPS, which are designed to autonomously isolate downstream facilities from overpressure situations. This document integrates these requirements to address the specific needs of subsea production. These requirements cover the HIPPS pressure sensors, logic solver, shutdown valves, and ancillary devices including testing, communications, and monitoring subsystems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d9dbac98-2dc5-4e51-b009-eed1f0dfc9c1.htm 01-Oct-09
    API RP 17P 2ND ED (2019) Recommended Practice for Subsea Structures and Manifolds; Second Edition This document addresses recommendations for subsea structures and manifolds, within the frameworks set forth by recognized and accepted industry specifications and standards.

    Equipment within the scope of this document is listed below (see Figure 1):

    a)the following structural components and piping systems of subsea production systems:

    — production and injection manifolds,

    — modular and integrated single satellite and multi-well templates,

    — subsea processing and subsea boosting stations,

    — flow control modules,

    — flowline riser bases and export riser bases,

    — pipeline end manifolds (PLEM),

    — pipeline end terminations (PLET),

    — T- and Y-connections,

    — subsea isolation valves (SSIV);

    b)the following structural components of subsea production system:

    — subsea controls and distribution structures,

    — other subsea structures;

    c)protection structures associated with the above components;

    d)foundations and mounting bases to support above structures;

    The following components and their applications are outside the scope of this document:

    — pipeline and manifold valves;

    — flowline and tie-in connectors;

    — choke valves;

    — flow control valves;

    — multi-phase flow meters;

    — pressure vessels;

    — production control systems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8ce02ced-dcaf-4d86-b198-ad4e212b9e6e.htm 01-Jan-19
    API RP 17Q 1ST ED (2010) Subsea Equipment Qualification—Standardized Process for Documentation; First Edition This recommended practice (RP) provides guidance on relevant qualification methods that may be applied to facilitate subsea project execution. Qualification of subsea equipment is based on a breakdown of individual subsea components and categorization of those individual components based on classes of equipment and component functionality. A comprehensive component-level breakdown can cater to wide flexibility for field-specific configurations. The qualification process presented in this recommended practice is governed by component-level evaluation and referencing using two separate forms of documentation: failure mode assessments (FMAs) and product qualification sheets (PQSs). Detailed documentation resources related to the proactive qualification methodology presented in this recommended practice are provided in the annexes. These resources include an index of components and individual PQS documents. Documents relating to manufacturing inspection and Factory Acceptance Testing are outside the scope of this document.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/cd0c0e1d-16d3-4196-91ba-c57101eec964.htm 01-Jun-10
    API RP 17Q 2ND ED (2018) Recommended Practice on Subsea Equipment Qualification; Second Edition This recommended practice (RP) provides suppliers, contractors, and operators with process-level guidance to qualify equipment intended for use in subsea applications. This document is intended to provide high-level guidance only, so that the industry will have a common set of principles to follow for equipment qualification. It is not intended to replace existing company processes or procedures. The application of this recommended practice is dependent on the stakeholder companies (qualifier and end user) accepting its use. Although developed for application to subsea equipment, the process described by the RP can be applied to non-subsea equipment as well.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/bd082b4b-d8ee-4245-a0cf-b6ac9367f6b2.htm 01-May-18
    API RP 17Q DATA SHEETS Data Sheets for Subsea Equipment Qualification—Standardized Process for Documentation Electronically formatted mechanical equipment standard datasheet (Excel 5.0 spreadsheet).

    The file count for this data sheet set is 1.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d7d3827a-fdc1-48f8-be52-f31976a39c41.htm 01-Jan-17
    API RP 17R 1ST ED (2015) Recommended Practice for Flowline Connectors and Jumpers; First Edition This recommended practice (RP) addresses specific requirements and recommendations for subsea flowline connectors and jumpers within the frameworks set forth by recognized and accepted industry specifications and standards. As such, it does not supersede or eliminate any requirement imposed by any other industry specification.

    This RP covers subsea flowline connectors and jumpers used for pressure containment in both subsea production of oil and gas, and subsea injection services. Equipment within the scope of this document is listed below.

    — Equipment used to make the following subsea connections are included:

    — pipeline end terminations to manifolds,

    — pipeline end terminations to trees,

    — pipeline end terminations to riser bases,

    — manifolds to trees,

    — pipeline inline sleds to other subsea structures.

    — The following connection components and systems are included:

    — jumper assemblies,

    — monobore connectors systems,

    — multibore connectors systems,

    — pressure and flooding caps,

    — connector actuation tools.

    The following components and their applications are outside the scope of this RP:

    — subsea structures,

    — hydraulic, electrical, and fiber optic flying leads,

    — umbilicals,

    — pig launcher/receiver equipment,

    — specialized ROV and other tooling.

    Equipment for use in high-pressure high-temperature (HPHT) environments is beyond the scope of this document (see API 17TR8 for guidance on subsea HPHT applications).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/2cdf610d-c7cb-43e3-9b9d-885d21314760.htm 01-Mar-15
    API RP 17S 1ST ED (2015) Recommended Practice for the Design, Testing, and Operation of Subsea Multiphase Flow Meters; First Edition This document provides recommendations for the sizing, specification, system integration, and testing of subsea flow meters [henceforth referred to as multiphase flow meters (MPFMs)] for measurement of full stream, multiphase flow. This Recommended Practice (RP) includes wet gas flow meters as a subset of MPFMs. In-line MPFMs are typically used in subsea applications and are the focus of this RP.

    These recommendations and guidelines are intended for use by the engineer responsible for the delivery of the MPFM. Due to the nature of multiphase flow measurement it is anticipated that a cross-disciplinary team may be involved throughout its deployment and operational life.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0c13535e-9419-472d-8110-a6ce2484f938.htm 01-Jun-15
    API RP 17U 1ST ED (2015) Recommended Practice for Wet and Dry Thermal Insulation of Subsea Flowlines and Equipment; First Edition This recommended practice (RP) provides guidance for the performance, qualification, application, quality control, handling, and storage requirements of wet and dry thermal insulation for subsea applications in the petroleum and gas industries. This guideline also covers the inspection of the insulation, and the repair of insulation defects. For flowlines, the installation method is not defined and may be either S-lay, J-lay, or reel-lay. This guideline is intended to cover all three installation methods. This guideline also takes into consideration the design and structural handling of subsea trees, manifolds, pipeline end terminations (PLETs), flowline jumpers, etc. as it pertains to the placement of structure, sacrificial anodes, handling appurtenances, etc. to ensure the integrity of the insulation’s construction.

    Annex A specifies the minimum requirements for the performance qualification testing and inspection testing requirements for wet insulation systems (insulations in direct contact with seawater).

    Annex B specifies the minimum requirements for the performance qualification testing and inspection testing requirements for dry insulation systems (insulations not in direct contact with seawater).

    This document is not intended to address either installation procedures or proprietary fabrication of any particular insulation type.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b4ad230b-95ff-40b6-a574-f5e77947443c.htm 01-Feb-15
    API RP 17V 1ST ED (2015) Recommended Practice for Analysis, Design, Installation, and Testing of Safety Systems for Subsea Applications; First Edition 1.1 General

    This recommended practice (RP) presents recommendations for designing, installing, and testing a process safety system for subsea applications. The basic concepts of subsea safety systems are discussed and protection methods and requirements of the system are outlined.

    For the purposes of this RP, ‘subsea system’ includes all process components from the wellhead (and surface controlled subsurface safety valve [SCSSV]) to upstream of the boarding shutdown valve. For gas injection, water injection, and gas lift systems, the shutdown valve is within the scope of API 17V. This also includes the chemical injection system. Refer to Figure 1.

    This document is a companion document to API 14C, which provides guidance for topsides safety systems on offshore production facilities. Some sections of this document refer to API 14C for safety system methodology and processes. This RP illustrates how system analysis methods can be used to determine safety requirements to protect any process component. Actual analyses of the principal components are developed in such a manner that the requirements determined will be applicable whenever the component is used in the process. The safety requirements of the individual process components may then be integrated into a complete subsea safety system. The analysis procedures include a method to document and verify system integrity. The uniform method of identifying and symbolizing safety devices is presented in API 14C and adopted in this RP.

    Subsea systems within the scope of this document include:

    — subsea trees (production and injection), flowlines, and SCSSVs;

    — chemical injection lines;

    — manifolds;

    — subsea separation;

    — subsea boosting;

    — subsea compression;

    — flowlines;

    — gas lift;

    — high integrity pressure protection system (HIPPS);

    — subsea isolation valves;

    — risers;

    — hydraulic power unit.

    The safety system includes valves and flow control devices in the production system. The safety system also includes sensors installed in the production system to detect abnormal conditions and allow corrective action to be taken (whether manual or automatic).

    The intention is to design subsea safety systems to meet the requirements of IEC 61511; this document supplements these requirements.

    Procedures for testing common safety devices are presented with recommendations for test data, test frequency, and acceptable test tolerances.

    Instrumentation logic circuits are not discussed since these should be left to the discretion of the designer as long as the recommended safety functions are accomplished. Rotating machinery is considered in this RP as a unitized process component as it interfaces with the subsea safety system. When rotating machinery (such as a pump or compressor) is installed as a unit consisting of several process components, each component may be analyzed as prescribed in this RP.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/8219e300-6790-43c2-83b6-91d4e5f611be.htm 01-Feb-15
    API RP 17V 1ST ED (E1) Recommended Practice for Analysis, Design, Installation, and Testing of Safety Systems for Subsea Applications; First Edition This recommended practice (RP) presents recommendations for designing, installing, and testing a process safety

    system for subsea applications. The basic concepts of subsea safety systems are discussed and protection methods and requirements of the system are outlined.

    For the purposes of this RP, ‘subsea system’ includes all process components from the wellhead (and surface controlled subsurface safety valve [SCSSV]) to upstream of the boarding shutdown valve. For gas injection, water injection, and gas lift systems, the shutdown valve is within the scope of API 17V. This also includes the chemical injection system. Refer to Figure 1.

    This document is a companion document to API 14C, which provides guidance for topsides safety systems on offshore production facilities. Some sections of this document refer to API 14C for safety system methodology and processes. This RP illustrates how system analysis methods can be used to determine safety requirements to protect any process component. Actual analyses of the principal components are developed in such a manner that the requirements determined will be applicable whenever the component is used in the process. The safety requirements of the individual process components may then be integrated into a complete subsea safety system. The analysis procedures include a method to document and verify system integrity. The uniform method of identifying and symbolizing safety devices is presented in API 14C and adopted in this RP.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/2f042799-d8dd-4f1d-870d-b29a5ca59631.htm 01-Feb-15
    API RP 17W 1ST ED (2014) Recommended Practice for Subsea Capping Stacks; First Edition This document provides subsea capping stack recommended practices for design, manufacture, and use. The document applies to the construction of new subsea capping stacks and can be used to improve existing subsea capping stacks. The document can aid in generating a basis of design (BOD) document as well as preservation, transportation, maintenance, testing documents, and operating instructions.

    This document presents recommendations for neither procedures nor equipment for containment systems that may be connected to a subsea capping stack. All equipment and operations downstream of the subsea capping stack are considered part of a containment system and are not within the scope of this recommended practice.

    Annex A contains a discussion of possible subsea capping contingency procedures. Annex B contains example procedures for deployment, well shut-in and recovery of a subsea capping stack.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e85bd888-85b6-4bfb-99fe-9f8acc8078e0.htm 01-Jul-14
    API RP 19B 1ST ED (E1) Recommended Practices for Evaluation of Well Perforators; First Edition 0.1 GENERAL

    This Recommended Practice describes standard procedures for evaluating the performance of perforating equipment so that representations of this performance may be made to the industry under a standard practice. This document supersedes all previously issued editions of API RP 43.

    Sections 1-4 of this publication provide means for evaluating perforating systems (multiple shot) in 4 ways:

    1. Performance under ambient temperature and atmospheric pressure test conditions.

    2. Performance in stressed Berea sandstone targets (simulated wellbore pressure test conditions).

    3. How performance may be changed after exposure to elevated temperature conditions.

    4. Flow performance of a perforation under specific stressed test conditions.

    The purpose of this Recommended Practice is to specify the materials and methods used to evaluate objectively the performance of perforating systems or perforators.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/64dcff16-b9f8-4951-84e6-a804a4349489.htm 01-Nov-00
    API RP 19B 2ND ED (2006) Recommended Practices for Evaluation of Well Perforators; Second Edition 0.1 GENERAL

    This Recommended Practice describes standard procedures for evaluating the performance of perforating equipment so that representations of this performance may be made to the industry under a standard practice. This document supersedes all previously issued editions of API RP 43.

    Sections 1 – 4 of this Recommended Practice provides means for evaluating perforating systems (multiple shot) in 4 ways:

    1. Performance under ambient temperature and atmospheric pressure test conditions.

    2. Performance in stressed Berea sandstone targets (simulated wellbore pressure test conditions).

    3. How performance may be changed after exposure to elevated temperature conditions.

    4. Flow performance of a perforation under specific stressed test conditions.

    Section 5 of this Recommended Practice provides a procedure to quantify the amount of debris that comes out of a perforating gun during detonation. The purpose of this Recommended Practice is to specify the materials and methods used to evaluate objectively the performance of perforating systems or perforators.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/fb43ef74-d454-4270-a30d-47e4988cb685.htm 01-Sep-06
    API RP 19B 2ND ED (A1) Recommended Practice for Evaluation of Well Perforators; Second Edition; Reaffirmed, April 2011 0.1 GENERAL

    This Recommended Practice describes standard procedures for evaluating the performance of perforating equipment so that representations of this performance may be made to the industry under a standard practice. This document supersedes all previously issued editions of API RP 43.

    Sections 1 – 4 of this Recommended Practice provides means for evaluating perforating systems (multiple shot) in 4 ways:

    1. Performance under ambient temperature and atmospheric pressure test conditions.

    2. Performance in stressed Berea sandstone targets (simulated wellbore pressure test conditions).

    3. How performance may be changed after exposure to elevated temperature conditions.

    4. Flow performance of a perforation under specific stressed test conditions.

    Section 5 of this Recommended Practice provides a procedure to quantify the amount of debris that comes out of a perforating gun during detonation. The purpose of this Recommended Practice is to specify the materials and methods used to evaluate objectively the performance of perforating systems or perforators.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/59068db9-0aed-45eb-a073-b9069af981b3.htm 01-Sep-06
    API RP 19B 2ND ED (A1) (A2) Recommended Practices for Evaluation of Well Perforators; Second Edition; Reaffirmed, April 2011 0.1 GENERAL

    This Recommended Practice describes standard procedures for evaluating the performance of perforating equipment so that representations of this performance may be made to the industry under a standard practice. This document supersedes all previously issued editions of API RP 43.

    Sections 1 – 4 of this Recommended Practice provides means for evaluating perforating systems (multiple shot) in 4 ways:

    1. Performance under ambient temperature and atmospheric pressure test conditions.

    2. Performance in stressed Berea sandstone targets (simulated wellbore pressure test conditions).

    3. How performance may be changed after exposure to elevated temperature conditions.

    4. Flow performance of a perforation under specific stressed test conditions.

    Section 5 of this Recommended Practice provides a procedure to quantify the amount of debris that comes out of a perforating gun during detonation. The purpose of this Recommended Practice is to specify the materials and methods used to evaluate objectively the performance of perforating systems or perforators.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/bf8d2424-19a9-4583-830f-e92fde038398.htm 01-Sep-06
    API RP 19B 2ND ED (R 2011) Recommended Practice for Evaluation of Well Perforators; Second Edition; Reaffirmed, April 2011 0.1 GENERAL

    This Recommended Practice describes standard procedures for evaluating the performance of perforating equipment so that representations of this performance may be made to the industry under a standard practice. This document supersedes all previously issued editions of API RP 43.

    Sections 1 – 4 of this Recommended Practice provides means for evaluating perforating systems (multiple shot) in 4 ways:

    1. Performance under ambient temperature and atmospheric pressure test conditions.

    2. Performance in stressed Berea sandstone targets (simulated wellbore pressure test conditions).

    3. How performance may be changed after exposure to elevated temperature conditions.

    4. Flow performance of a perforation under specific stressed test conditions.

    Section 5 of this Recommended Practice provides a procedure to quantify the amount of debris that comes out of a perforating gun during detonation. The purpose of this Recommended Practice is to specify the materials and methods used to evaluate objectively the performance of perforating systems or perforators.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/24950cd8-195e-4ae3-aa94-9c3507aa6f66.htm 01-Sep-06
    API RP 19G10 1ST ED (2018) Design and Operation of Intermittent Gas-lift Systems; First Edition This API recommended practice provides guidelines and considerations for the design and operation of intermittent gas-lift systems including designs with chamber and plunger lift equipment. Included are the background and theory of each of these systems as well as considerations for system design and operation.

    This information is intended for well engineers who seek to gain a general understanding of the theory and practices of intermittent gas-lift systems.

    Not addressed in this recommended practice are absolutes in the development of an intermittent gas-lift system design or operation because of the range of variables for each well and field combination.

    This document also contains three annexes. Annex A contains mathematical derivations and models of some of the most pertinent intermittent gas-lift calculations. Annex B contains a comprehensive example of an intermittent gas-lift design. Annex C describes how to use the Field (U.S. Customary) Units Calculator and SI Units Calculator.

    The calculations described within the recommended practice are separately provided within excel spreadsheets to allow the effective use of this information by users of this document. They are referenced within text boxes inserted into the text prior to the details of the formulas. The spreadsheets can be downloaded here: <a href="http://alrdc.com">http://alrdc.com


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fa752277-1420-43fd-8438-1edf09b8ce5b.htm 01-Sep-18
    API RP 19G10 WORKSHEETS (2018) Worksheets for Design and Operation of Intermittent Gas-lift Systems; First Edition This API recommended practice provides guidelines and considerations for the design and operation of intermittent gas-lift systems including designs with chamber and plunger lift equipment. Included are the background and theory of each of these systems as well as considerations for system design and operation.

    This information is intended for well engineers who seek to gain a general understanding of the theory and practices of intermittent gas-lift systems.

    Not addressed in this recommended practice are absolutes in the development of an intermittent gas-lift system design or operation because of the range of variables for each well and field combination.

    This document also contains three annexes. Annex A contains mathematical derivations and models of some of the most pertinent intermittent gas-lift calculations. Annex B contains a comprehensive example of an intermittent gas-lift design. Annex C describes how to use the Field (U.S. Customary) Units Calculator and SI Units Calculator.

    The calculations described within the recommended practice are separately provided within excel spreadsheets to allow the effective use of this information by users of this document. They are referenced within text boxes inserted into the text prior to the details of the formulas. The spreadsheets can be downloaded here: <a href="http://alrdc.com">http://alrdc.com</a>


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/731ae469-662c-4c0a-80e0-49113afa227d.htm 01-Sep-18
    API RP 19G11 1ST ED (2018) Dynamic Simulation of Gas-lift Wells and Systems; First Edition This recommended practice (RP) provides guidance and background for the application and use of dynamic simulation of gas-lift wells and their related systems. Discussion is included for use of steady-state, “pseudo” steady-state, and dynamic numerical models. Also presented are guidelines to facilitate the application of these techniques to optimize well/system integrity, operations, life cycle design, and production. Additionally, a range of artificial lift and natural flowing systems and topics (e.g. gas well liquid loading) are addressed. The dynamic simulation recommendations (e.g. stable flow, hydrates, waxes, corrosion, liquid loading, and complex wells) can be implemented in other production systems (e.g. natural flowing wells).

    This RP is also designated for managers, production technologists, reservoir engineers, facilities engineers, production engineers, well testing engineers, well analysts, operators, and researchers who want to gain a general understanding of dynamic simulation, areas of application, added values, and benefits. The contents compare transient vs steady-state techniques and provide readers with when and how each technique may be effectively applied.

    Not included are technical requirements for the hardware of the dynamic simulation system, the specifics of the system calculations, the responses to the output of the dynamic simulation data output, and specifics of what actions are required after the provided data is considered.

    An extensive bibliography is provided of documents for additional information on the topics included.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b72aa945-f5a4-4149-b1b6-5c552b51be3c.htm 01-Oct-18
    API RP 19G5 1ST ED (2019) Operation, Maintenance, Surveillance, and Troubleshooting of Gas-lift Installations; First Edition This recommended practice (RP) provides guidance, background, and requirements for the application and use of gas-lift wells and their related systems. Discussion is included for operation, maintenance, surveillance, and troubleshooting of gas-lift wells and installations.

    This RP is intended for use by managers, production technologists, reservoir engineers, facilities engineers, production engineers, well testing engineers, well analysts, operators, and researchers who want to gain a general understanding of gas-lift wells and gas-lift operations. It can be used to prepare and present courses on gas-lift wells and operations.

    This RP focuses primarily on continuous gas-lift. However, use of intermittent gas-lift, dual gas-lift, and gas-lift for gas wells is mentioned.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b11f42cf-d817-4bd1-84cd-fcd3f07fe5df.htm 01-Jul-19
    API RP 19G9 1ST ED (2010) Design, Operation, and Troubleshooting of Dual Gas-Lift Wells; First Edition This document provides recommended practices for the design, operation, optimization, and troubleshooting of dual gas-lift wells.

    Compared to single completions, dual completions have a higher initial cost, have more operating problems, are more difficult and expensive to work over, and often produce less efficiently. Based on experience, most technical gas-lift specialists and operations staff prefer single completions to duals.

    It is not the purpose of this document to recommend the practice of dual gas lift. In many cases, dual gas lift is problematic and often it is ineffective. Often it is difficult or even impossible to effectively produce both completions in a dual well using gas lift, over the long term. If there are other feasible alternatives to produce dual wells, they should be considered.

    However, many dually completed oil wells should be artificially lifted—initially or after reservoir pressures have declined and/or water cuts have increased. And in many cases, the only practical or feasible method of artificial lift for these wells is gas lift. So, if dual wells must be artificially lifted, and if the only practical or feasible means to do this is with gas lift, every effort should be made to perform this dual gas-lift function as effectively as possible.

    Therefore, the purpose of this document is to offer recommended practices, guidelines, and tools to make the best of what may otherwise be a difficult situation. This document also contains suggestions on practices that should be avoided to minimize problems, inefficiencies, and poor economics that may be associated with ineffective dual gas-lift operations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f707cd79-1d4c-434d-a784-b97115f26547.htm 01-Feb-10
    API RP 19G9 2ND ED (2015) Design, Operation, and Troubleshooting of Dual Gas-Lift Wells; Second Edition This document provides recommended practices (RPs) for the selection, design, operation, surveillance, optimization, automation, and troubleshooting of dual gas-lift wells. The purpose of this document is to present RPs, guidelines, and tools to help obtain optimum production from dual gas-lift wells.

    This document also contains practices that should be avoided to minimize problems and inefficiencies that can be associated with ineffective dual gas-lift operations. Compared to single completions, dual completions typically have more operating problems, are more difficult to work over, and can produce less efficiently.

    It is not the purpose of this document to recommend the practice of dual gas-lift. In some cases, dual gas-lift is problematic and often ineffective. Often it is difficult or even impossible to effectively produce both completions in a dual well using gas-lift over the long term. Where there are other feasible alternatives to produce dual wells, they should be considered. However, many dually completed oil wells should be artificially lifted initially or after reservoir pressures have declined and/or water cuts have increased. In many cases, the only practical method of artificial lift for these wells is gas-lift. Therefore, every effort should be made to design and operate dual gas-lift systems as effectively as possible. Annexes to this RP include: a) an overview of dual gas-lift systems, b) dual gas-lift mandrel spacing designs, c) dual gas-lift unloading valve design for production pressure operated (PPO) valves, and d) dual gas-lift practices not recommended.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6edc4f6d-2ca6-4059-9b52-d44ccd940163.htm 01-Apr-15
    API RP 1FSC 1ST ED (2013) Facilities Systems Completion Planning and Execution; First Edition This document applies to a wide variety of projects within the oil and gas industry excluding subsurface. Although intended for oil and gas industry, the process described in this document can be applied to other industries as well. It is intended that the processes and practices established herein can be adapted and applied from a single piece of tagged equipment to a complex petrochemical facility. The process described within is intended to be applied at a system level.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a4eea0d9-41b7-472f-84e3-a76b4da1b86a.htm 01-Jul-13
    API RP 2A-LRFD 1ST ED (1993) Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms — Load and Resistance Factor Design; First Edition This "Recommended Practice for Planning, Designing, and Constructing Fixed Offshore Platforms - Load and Resistance Factor Design" (LRFD) contains the engineering design principles and good practices that have been the basis of the API RP2A working strength design (WSD) recommended practice, now in its 20th Edition. The LRFD provisions have been developed from the WSD provisions using reliability based calibration.</p:>

    This recommended practice is based on sound engineering principles, extensive testing and field application experience. In no case is any specific recommendation included which could not be accomplished by presently available techniques and equipment. Consideration is given in all cases to the safety of personnel, compliance with existing regulations, and prevention of pollution.</p:>

    This is the First Edition of the "Recommended Practice for Planning, Designing, and Constructing Fixed Offshore Platforms - Load and Resistance Factor Design." This practice has been approved by the API as an alternative to the 20th Edition of the RP2A "Recommended Practice for Planning, Designing, and Constructing Fixed Offshore Platforms."</p:>

    The LRFD was first issued in December 1989 in draft form. It was consistent in most respects with the 18th Edition of the RP2A. The draft was open to comment for a period of two years. All of the comments received were carefully considered in the development of the First Edition. In general, the provisions are consistent with the 20th Edition of the RP2A.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e496d3f0-026b-439f-9b37-0c0b64286920.htm 01-Jul-93
    API RP 2A-LRFD 2ND ED (2019) Planning, Designing, and Constructing Fixed Offshore Platforms—Load and Resistance Factor Design; First Edition This document provides requirements for the design, fabrication, transportation, installation, modification, and structural integrity management for the topsides structure for an oil and gas platform; API 2TOP complements API 2A-WSD, API 2A-LRFD, ISO 19903, API 2FPS, API 2T, ISO 19905-1, and API 2N, which give requirements for various forms of substructures. It is based on ISO 19901-3:2010 (Corrected version, 15-Dec-2011) and is consistent with ISO 19901-3:2014 to the fullest extent possible and modified only where needed for API purposes. Requirements in this standard concerning modifications and maintenance relate only to those aspects that are of direct relevance to the structural integrity of the topsides structure. </p:>

    The actions on the topsides structure and structural components are derived from this document and where necessary, in combination with API, other international standards and the ISO 19900 series. The resistances of structural components of the topsides structure are determined by the use of international or national building codes, as specified in this document. If the topsides structure is integrated with the supporting substructure to help resist global platform forces, the requirements of this standard are supplemented with applicable requirements of the associated substructure such as API 2A-LRFD for fixed steel structures and API 2FPS for floating structures. This document is applicable to:

    For those parts of floating offshore structures and mobile offshore units that are chosen to be governed by the rules of a recognized classification society, the corresponding class rules supersede the associated requirements of this standard.

    This document has limited guidance on corrosion control, alternate structural materials, and other miscellaneous topics that the structural engineer often has to consider.

    This document contains requirements for, as well as guidance and information on, the following aspects of topsides structures:

    This document applies to structural components including the following:

  • structural components in decks, module support frames, and modules;
  • flare structures;
  • crane pedestal and other crane support arrangements;
  • helicopter landing decks (helidecks);
  • permanent bridges between separate offshore structures;
  • masts, towers, and booms on offshore structures.
  • http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/ee123d17-f1ca-4c8f-9832-054e1f6656e3.htm 01-Aug-19
    API RP 2A-WSD 22ND ED (2014) Planning, Designing, and Constructing Fixed Offshore Platforms— Working Stress Design; Twenty-Second Edition This recommended practice is based on global industry best practices and serves as a guide for those who are concerned with the design and construction of new fixed offshore platforms and for the relocation of existing platforms used for the drilling, development, production, and storage of hydrocarbons in offshore areas.

    NOTE 1 Specific guidance for hurricane conditions in the Gulf of Mexico and other U.S. offshore areas, previously provided in API 2A-WSD, 21st Edition, Section 2, is now provided in API 2MET.

    NOTE 2 Specific guidance for earthquake loading in U.S. offshore areas, previously provided in the API 2A-WSD, 21st Edition, Section 2, is now provided in API 2EQ.

    NOTE 3 Specific guidance for soil and foundation considerations in offshore areas, previously provided in API 2A-WSD, 21st Edition, Section 6, is now provided in API 2GEO.

    NOTE 4 Specific guidance for the evaluation of structural damage, above and below water structural inspection, fitness-for-purpose assessment, risk reduction and mitigation planning, plus the process of decommissioning has been removed and is now provided in API 2SIM.

    NOTE 5 Specific guidance for fire and blast loading, previously provided in the 2A-WSD, 21st Edition, Section 18, is now provided in API 2FB [3].

    NOTE 6 Specific guidance for marine operations, supplementing the guidance provided in this document, is now provided in API 2MOP [6]. The provisions in API 2A-WSD shall govern if there are any conflicts.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/b9e32dec-268b-404d-988e-5cda65c27757.htm 01-Nov-14
    API RP 2D 7TH ED (2014) Operation and Maintenance of Offshore Cranes; Seventh Edition 1.1 This recommended practice establishes general principles for the safe operation and maintenance of offshore pedestal-mounted revolving cranes on fixed or floating offshore platforms, offshore support vessels, jackup drilling rigs, semi-submersible drilling rigs and other types of mobile offshore drilling units (MODUs). This document also provides requirements and recommendations for personnel training, lift planning, preuse inspection, and testing of temporary cranes that are erected offshore.

    1.2 Typical applications can include, but are not limited to the following.

    a) Offshore oil exploration and production applications; these cranes are typically mounted on a fixed (bottom-supported) structure, floating platform structure, or ship-hulled vessel used in drilling and production operations for offshore minerals and energy.

    b) Shipboard applications; these lifting devices (rated for 10,000 lbs [4536 kg] or more) are mounted on surface-type vessels and are used to move materials, containers, ROVs, diving bells, pipeline, subsea components, and other materials on the vessel, between vessels, into the sea, or to the sea bed.

    c) Heavy-lift applications; cranes for heavy-lift applications are mounted on barges, self-elevating vessels or other vessels, and are used in construction and salvage operations above and below the sea surface.

    1.3 Equipment (e.g. davits, launch frames) used only for launching life-saving appliances (life boats or life rafts) are not included in the scope of this recommended practice.

    1.4 Lifting devices not covered by this document should be operated, inspected, and maintained in accordance with the manufacturer’s recommendations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/8eb6abc2-5b69-4fc9-b7fc-7e8b29191eef.htm 01-Dec-14
    API RP 2D 7TH ED (E1) Operation and Maintenance of Offshore Cranes; Seventh Edition 1.1 This recommended practice establishes general principles for the safe operation and maintenance of offshore pedestal-mounted revolving cranes on fixed or floating offshore platforms, offshore support vessels, jackup drilling rigs, semi-submersible drilling rigs and other types of mobile offshore drilling units (MODUs). This document also provides requirements and recommendations for personnel training, lift planning, preuse inspection, and testing of temporary cranes that are erected offshore.

    1.2 Typical applications can include, but are not limited to the following.

    a) Offshore oil exploration and production applications; these cranes are typically mounted on a fixed (bottom-supported) structure, floating platform structure, or ship-hulled vessel used in drilling and production operations for offshore minerals and energy.

    b) Shipboard applications; these lifting devices (rated for 10,000 lbs [4536 kg] or more) are mounted on surface-type vessels and are used to move materials, containers, ROVs, diving bells, pipeline, subsea components, and other materials on the vessel, between vessels, into the sea, or to the sea bed.

    c) Heavy-lift applications; cranes for heavy-lift applications are mounted on barges, self-elevating vessels or other vessels, and are used in construction and salvage operations above and below the sea surface.

    1.3 Equipment (e.g. davits, launch frames) used only for launching life-saving appliances (life boats or life rafts) are not included in the scope of this recommended practice.

    1.4 Lifting devices not covered by this document should be operated, inspected, and maintained in accordance with the manufacturer’s recommendations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/248bcb0b-5394-483f-b38d-e6b625960407.htm 01-Dec-14
    API RP 2EQ 1ST ED (2014) Seismic Design Procedures and Criteria for Offshore Structures; First Edition; ISO 19901-2:2004 This standard contains requirements for defining the seismic design procedures and criteria for offshore structuresand is a modified adoption of ISO 19901-2. The intent of the modification is to map the requirements of ISO 19901-2 to the United States' offshore continental shelf (U.S. OCS). The requirements are applicable to fixed steel structuresand fixed concrete structures. The effects of seismic events on floating structures and partially buoyant structures are also briefly discussed. The site-specific assessment of jack-ups in elevated condition is only covered to the extent that the requirements are applicable.

    This document defines the seismic requirements for new construction of structures in accordance with API 2A-WSD,22nd Edition and later. Earlier editions of API 2A-WSD are not applicable.

    The majority of the ISO 19901-2 document is applicable to the U.S. OCS. Where necessary, this document provides guidance for aligning the ISO 19901-2 requirements and terminology with API. The key differences are as follows.

    a) API 2EQ adopts the ISO 19901-2 site seismic zones in lieu of those previously used in API 2A-WSD, 21st Edition and earlier.

    b) Only the maps in Figure B.2 are applicable, in lieu of those previously used in API 2A-WSD, 21st Edition and earlier.

    c) ISO 19901-2 seismic design approach is also adopted here with:

    — a two-level seismic design in which the structure is designed to the ultimate limit state (ULS) for strength and stiffness and then checked to the abnormal or accidental limit state (ALS) to ensure that it meets reserve strength and energy dissipation requirements;

    — the seismic ULS design event is the extreme level earthquake (ELE) [this is consistent with, but not exactly the same as the strength level earthquake (SLE) in API 2A-WSD, 21st Edition and earlier];

    — the seismic ALS design event is the abnormal level earthquake (ALE) [this is consistent with, but not exactly the same as the ductility level earthquake (DLE) in API 2A-WSD, 21st Edition and earlier].

    Only earthquake-induced ground motions are addressed in detail. Other geologically induced hazards such as liquefaction, slope instability, faults, tsunamis, mud volcanoes, and shock waves are mentioned and briefly discussed.

    The requirements are intended to reduce risks to persons, the environment, and assets to the lowest levels that are reasonably practicable. This intent is achieved by using:

    — seismic design procedures which are dependent on the platform's exposure level and the expected intensity of seismic events;

    — a two-level seismic design check in which the structure is designed to the ultimate limit state (ULS) for strength and stiffness and then checked to abnormal environmental events or the accidental limit state (ALS) to ensure that it meets reserve strength and energy dissipation requirements.

    For high seismic areas and/or high exposure level fixed structures, a site-specific seismic hazard assessment is required; for such cases, the procedures and requirements for a site-specific probabilistic seismic hazard analysis (PSHA) are addressed. However, a thorough explanation of PSHA procedures is not included.

    Where a simplified design approach is allowed, worldwide offshore maps are included in Annex B that show the intensity of ground shaking corresponding to a return period of 1000 years. In such cases, these maps may be used with corresponding scale factors to determine appropriate seismic actions for the design of a structure.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c8853482-08c3-4690-b2f1-69575899854e.htm 01-Nov-14
    API RP 2EQ 1ST ED (A1) Seismic Design Procedures and Criteria for Offshore Structures; First Edition; ISO 19901-2:2004 This standard contains requirements for defining the seismic design procedures and criteria for offshore structuresand is a modified adoption of ISO 19901-2. The intent of the modification is to map the requirements of ISO 19901-2 to the United States' offshore continental shelf (U.S. OCS). The requirements are applicable to fixed steel structuresand fixed concrete structures. The effects of seismic events on floating structures and partially buoyant structures are also briefly discussed. The site-specific assessment of jack-ups in elevated condition is only covered to the extent that the requirements are applicable.

    This document defines the seismic requirements for new construction of structures in accordance with API 2A-WSD,22nd Edition and later. Earlier editions of API 2A-WSD are not applicable.

    The majority of the ISO 19901-2 document is applicable to the U.S. OCS. Where necessary, this document provides guidance for aligning the ISO 19901-2 requirements and terminology with API. The key differences are as follows.

    a) API 2EQ adopts the ISO 19901-2 site seismic zones in lieu of those previously used in API 2A-WSD, 21st Edition and earlier.

    b) Only the maps in Figure B.2 are applicable, in lieu of those previously used in API 2A-WSD, 21st Edition and earlier.

    c) ISO 19901-2 seismic design approach is also adopted here with:

    — a two-level seismic design in which the structure is designed to the ultimate limit state (ULS) for strength and stiffness and then checked to the abnormal or accidental limit state (ALS) to ensure that it meets reserve strength and energy dissipation requirements;

    — the seismic ULS design event is the extreme level earthquake (ELE) [this is consistent with, but not exactly the same as the strength level earthquake (SLE) in API 2A-WSD, 21st Edition and earlier];

    — the seismic ALS design event is the abnormal level earthquake (ALE) [this is consistent with, but not exactly the same as the ductility level earthquake (DLE) in API 2A-WSD, 21st Edition and earlier].

    Only earthquake-induced ground motions are addressed in detail. Other geologically induced hazards such as liquefaction, slope instability, faults, tsunamis, mud volcanoes, and shock waves are mentioned and briefly discussed.

    The requirements are intended to reduce risks to persons, the environment, and assets to the lowest levels that are reasonably practicable. This intent is achieved by using:

    — seismic design procedures which are dependent on the platform's exposure level and the expected intensity of seismic events;

    — a two-level seismic design check in which the structure is designed to the ultimate limit state (ULS) for strength and stiffness and then checked to abnormal environmental events or the accidental limit state (ALS) to ensure that it meets reserve strength and energy dissipation requirements.

    For high seismic areas and/or high exposure level fixed structures, a site-specific seismic hazard assessment is required; for such cases, the procedures and requirements for a site-specific probabilistic seismic hazard analysis (PSHA) are addressed. However, a thorough explanation of PSHA procedures is not included.

    Where a simplified design approach is allowed, worldwide offshore maps are included in Annex B that show the intensity of ground shaking corresponding to a return period of 1000 years. In such cases, these maps may be used with corresponding scale factors to determine appropriate seismic actions for the design of a structure.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/dfce5183-d6fc-4d5b-9306-1b701603e1d9.htm 01-Nov-14
    API RP 2FB 1ST ED (2006) Recommended Practice for the Design of Offshore Facilities Against Fire and Blast Loading; First Edition; Reaffirmed, January 2012 This document provides guidelines and recommended practice for the satisfactory design of offshore structures against fire and blast loading. For guidelines and recommended practice and other requirements relating to planning, designing and constructing offshore structures relevant API recommended practices, such as API RP 2A, API RP 2FPS, etc., should be followed. The Section 18 of API RP 2A, 21 st edition provided a brief overview of the issues associated with the design of fixed offshore structures against fire and blast loading. This document has no contradiction of the issues as identified in the Section 18 of API RP 2A, 21stedition, instead it expands on the details and includes various issues associated with floating structures previously not indicated.

    The scope of this document is mainly directed to the new design of offshore structures against fire and blast, but is also widely recommended for use in verifying existing offshore structures against fire and blast loading if the operator so desires.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/ed8221b3-b569-4d9f-9607-8c07bb8dc0a3.htm 01-Jan-12
    API RP 2FPS 2ND ED (2011) Planning, Designing, and Constructing Floating Production Systems; Second Edition This document provides requirements and guidance for the structural design and/or assessment of floating offshore platforms used by the petroleum and natural gas industries to support the following functions:

    — production;

    — storage and/or offloading;

    — drilling and production;

    — production, storage and offloading;

    drilling, production, storage and offloading.

    NOTE 1 Floating offshore platforms are often referred to using a variety of abbreviations, e.g. FPS, FSU, FPSO, etc. (see Clauses 3 and 4), in accordance with their intended mission.

    NOTE 2 In this standard, the term "floating structure", sometimes shortened to "structure", is used as a generic term to indicate the structural systems of any member of the classes of platforms defined above

    NOTE 3 In some cases, floating platforms are designated as "early production platforms". This term relates merely to an asset development strategy. For the purposes of this International Standard, the term "production" includes "early production".

    Its requirements do not apply to the structural systems of mobile offshore units (MOUs). These include, among others:

    — floating structures intended primarily to perform drilling and/or well intervention operations (often referred to as MODUs), even when used for extended well test operations;

    — floating structures used for offshore construction operations (e.g. crane barges or pipelay barges), for temporary or permanent offshore living quarters (floatels), or for transport of equipment or products (e.g. transportation barges, cargo barges), for which structures reference is made to relevant recognized classification society (RCS) rules.

    Its requirements are applicable to all possible life-cycle stages of the structures defined above, such as

    — design, construction and installation of new structures, including requirements for inspection, integrity management and future removal,

    — structural integrity management covering inspection and assessment of structures in-service, and

    — conversion of structures for different use (e.g. a tanker converted to a production platform) or reuse at different locations

    The following types of floating structure are explicitly considered within the context of this standard:

    a) monohulls (ship-shaped structures and barges);

    b) semi-submersibles;

    c) spars.

    In addition to the structural types listed above, this standard covers other floating platforms intended to perform theabove functions, consisting of partially submerged buoyant hulls made up of any combination of plated and space frame components and used in conjunction with the station keeping systems covered in API 2SK. These other structures can have a great range of variability in geometry and structural forms and, therefore, can be only partly covered by the requirements of this standard. In other cases, specific requirements stated in this standard can be found not to apply to all or part of a structure under design.

    In all the above cases, conformity with this standard will require that the design is based upon its underpinning principles and achieves a level of safety equivalent, or superior, to the level implicit in it.

    NOTE The speed of evolution of offshore technology often far exceeds the pace at which the industry achieves substantial agreement on innovation in structural concepts, structural shapes or forms, structural components and associated analysis and design practices, which are continuously refined and enhanced. On the other hand, International Standards can only capture explicitindustry consensus, which requires maturation and acceptance of new ideas. Consequently, advanced structural concepts can, in some cases, only be partly covered by the provisions of standard.

    This standard is applicable to steel floating structures. The principles documented herein are, however, considered to be generally applicable to structures fabricated in materials other than steel.

    Similarly, while this document is directly applicable to oil and gas producing platforms operating at ambient temperature, the principles documented herein are considered to be generally applicable to structures used in conjunction with cryogenic processes, such as floating liquefied gas (FLNG) plants, with the exception of the aspectsrelated to handling and storage of cryogenic liquids.

    The structural design and fabrication of the drilling and production modules supported by a floating structure can be carried out in accordance with API 2A–WSD, 21st Edition, Errata and Supplement 3.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/cae602f9-3de3-4c19-b40b-cf2839403520.htm 01-Oct-11
    API RP 2FSIM 1ST ED (2019) Floating Systems Integrity Management; First Edition 1 Scope

    This recommended practice (RP) provides guidance for floating system integrity management (FSIM) of floating production systems (FPSs), which include tension leg platforms (TLPs), used by the petroleum and natural gas industries to support drilling, production, storage, and/or offloading operations. FPSs described in this RP are governed by local regulatory requirements and recognized classification society (RCS) rules (if classed). No specific regulatory compliance or RCS requirements are restated in this RP. The requirements of this RP do not apply to mobile offshore drilling units (MODUs) or to mobile offshore units (MOUs) used in support of construction operations. For integrity management (IM) considerations, these units are typically governed by RCS rules, and include, among others:

    This RP does not address moorings or risers; these are addressed separately by API 2MIM and API 2RIM, respectively. Dynamic positioning is not covered in this RP.

    The following types of floating systems are explicitly covered by this RP:

    The following types of floating system components are included within the context of this RP:

    This RP is directly applicable to oil and gas producing floating systems operating at ambient temperature, including floating liquefied natural gas (FLNG) plants, except for the aspects related to handling and storage of cryogenic liquids.

    The FSIM process provided in this RP is applicable to floating systems installed at any location worldwide. However, the referenced metocean criteria has regional limitations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/03acb42e-10b2-48ff-b27e-700f175d0dc1.htm 01-Sep-19
    API RP 2GEO 1ST ED (A1) Geotechnical and Foundation Design Considerations; First Edition; ISO 19901-4:2003 This document contains requirements and recommendations for those aspects of geoscience and foundation engineering that are applicable to a broad range of offshore structures, rather than to a particular structure type. Such aspects are;

    — site characterization,

    — soil and rock characterization,

    — design and installation of foundations supported by the seabed (shallow foundations),

    — identification of hazards,

    — design of pile foundations, and

    — soil-structure interaction for risers, flowlines, and auxiliary subsea structures.

    Aspects of soil mechanics and foundation engineering that apply equally to offshore and onshore structures are not addressed. The user of this document is expected to be familiar with such aspects


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b6c6e7f5-6da7-46c2-97bb-54bd470f0401.htm 01-Oct-14
    API RP 2I 3RD ED (R 2015) In-service Inspection of Mooring Hardware for Floating Structures; Third Edition; Reaffirmed, June 2015 1.1 General

    This recommended practice provides guidelines for inspecting mooring components of mobile offshore drilling units (MODUs) and permanent floating installations. Although this document was primarily developed for the moorings of MODUs and permanent floating installations, some of the guidelines may be applicable to moorings of other floating vessels such as pipe-laying barges and construction vessels. Furthermore, some of the guidelines may be applicable to secondary or emergency moorings such as moorings for jack-up units, shuttle tanker moorings, and dynamic positioning (DP) vessel harbor mooring.

    The applicability of this document to the moorings of other floating vessels is left to the discretion of the user.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/47962862-d941-4a7a-b366-9bf4fc747b79.htm 01-Jun-15
    API RP 2L 4TH ED (R 2012) Recommended Practice for Planning, Designing, and Constructing Heliports for Fixed Offshore Plateforms; Fourth Edition; Effective Date June 1, 1996 This recommended practice provides a guide for planning, designing, and constructing heliports for fixed offshore platforms. It includes operational consideration guidelines, design load criteria, heliport size, marking recommendations, and other heliport design recommendations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/25dfe60c-55cd-4e55-9204-09bff88048b7.htm 01-May-96
    API RP 2MET 1ST ED (2014) Derivation of Metocean Design and Operating Conditions; First Edition; ISO 19901-1:2006 This part of ISO 19901 gives general requirements for the determination and use of meteorological and oceanographic (metocean) conditions for the design, construction and operation of offshore structures of all types used in the petroleum and natural gas industries.

    The requirements are divided into two broad types:

    1) those that relate to the determination of environmental conditions in general, together with the metocean parameters that are required to adequately describe them;

    2) those that relate to the characterization and use of metocean parameters for the design, the construction activities or the operation of offshore structures.

    The environmental conditions and metocean parameters discussed comprise

    — extreme and abnormal values of metocean parameters that recur with given return periods that are considerably longer than the design service life of the structure,

    — long-term distributions of metocean parameters, in the form of cumulative, conditional, marginal or joint statistics of metocean parameters, and

    — normal environmental conditions that are expected to occur frequently during the design service life of the structure.

    Metocean parameters are applicable to

    — the determination of actions and action effects for the assessment of existing structures, — the site-specific assessment of mobile offshore units, — the determination of limiting environmental conditions, weather windows, actions and action effects for pre-service and post-service situations (i.e. fabrication, transportation and installation or decommissioning and removal of a structure), and — the operation of the platform, where appropriate.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e4c0fe44-30f8-462d-9409-f91e4b5454ee.htm 01-Nov-14
    API RP 2MET 2ND ED (2019) Derivation of Metocean Design and Operating Conditions; Second Edition; ISO 19901-1:2015 1 Scope

    This standard gives general requirements for the determination and use of meteorological and oceanographic (metocean) conditions for the design, construction, and operation of offshore structures of all types used in the petroleum and natural gas industries.

    The requirements are divided into two broad types:

    The environmental conditions and metocean parameters discussed are as follows:

    Metocean parameters are applicable to:

    • the determination of actions for the design of new structures;
    • the determination of actions for the assessment of existing structures;
    • the site-specific assessment of mobile offshore units;
    • the determination of limiting environmental conditions, weather windows, actions and action effects for pre-service and post-service situations (i.e. fabrication, transportation and installation, or decommissioning and removal of a structure); and
    • facility operations, where appropriate.
    • NOTE Specific metocean requirements for site-specific assessment of jack-ups are contained in ISO 19905-1, for arctic offshore structures in ISO 19906, and for topside structures in ISO 19901-3.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/25febfb0-5e4c-4f37-b785-be828b8d04f7.htm 01-Nov-19
    API RP 2MIM 1ST ED (2019) Mooring Integrity Management; First Edition 1 Scope

    connected to a permanent floating production system (FPS) used for the drilling, development, production, and/or This recommended practice (RP) provides guidance for the integrity management (IM) of mooring systems storage of hydrocarbons in offshore areas. The scope of this RP extends from the anchor to the connection to the floating unit (e.g. chain stopper) and includes components critical to the mooring system (e.g. turret bearings, fairleads, chain stoppers, anchors, suction piles).

    Specific guidance is provided for the inspection, monitoring, evaluation of damage, fitness-for-service assessment, risk reduction, mitigation planning, and the process of decommissioning. This RP incorporates and expands on the IM recommendations found in API 2I and API 2SK. In the event of any discrepancy between API 2MIM and API 2I/API 2SK, API 2I/API 2SK will govern.

    This RP is not intended for:

    • structural steelwork of turret systems and TLP tendons, which are addressed by API 2FSIM;
    • thrusters, power generation, or control system;
    • mobile offshore drilling unit (MODU) or other temporary moorings that are deployed and retrieved frequently;
    • vessels holding station via a dynamic positioning (DP) system, without the use of mooring.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/890c8ea7-e0f3-4fb2-b49c-a3479a8ec469.htm 01-Sep-19
    API RP 2RIM 1ST ED (2019) Integrity Management of Risers from Floating Production Systems; First Edition 1 Scope

    This recommended practice (RP) provides guidance for the integrity management (IM) of risers connected to a permanent floating production system (FPS) used for the drilling, development, production, and storage of hydrocarbons in offshore areas. A riser is typically part of a larger subsea system extending from a wellhead, tree, manifold, template, or other structure on the seabed, to a boarding valve or pig trap on the host platform’s topsides. This RP addresses the integrity management of the dynamic portion of the riser system. For the purposes of this RP, a riser has a top boundary that is somewhere at or above the point where it transfers load to the platform structure, and it has a lower boundary where it transfers load into a foundation, which could be a wellhead, pipeline, or subsea structure. For a top-tensioned riser (TTR), the top boundary would typically be the tensioner system hang-off point, and the bottom boundary would be the wellhead. For a steel catenary riser (SCR), the top boundary would typically be the stress joint or flexible joint. Some unusual configurations such as pull-tube SCRs merit special consideration. The top boundaries of a flexible or hybrid riser are typically a flanged connection to the riser end fitting at the top of an I-tube or J-tube, and a bend stiffener at the bottom of a I-tube or J-tube. The IM of the structural support for a riser on the host platform is in the scope of API 2FSIM, although some hybrid configurations, such as pull tubes, can require overlapping riser and structural IM. For risers structurally connected to the platform below the topsides, hull piping can be structurally clamped to the hull up to a boarding valve or pig launcher at the topsides. This is intended to be considered as part of the riser in terms of IM, although it also has structural elements addressed in API 2FSIM.

    The scope of this RP includes:

    The scope of this RP specifically does not include:

    NOTE However, the interface of the riser with these components is important to the IM of the riser system.

    Specific recommendations are provided for the inspection, monitoring, evaluation of damage, fitness-for-service assessment, risk reduction, mitigation planning, and decommissioning of risers. This RP incorporates and expands on the integrity management recommendations found in API 2RD, API 17B, and API 17L2.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/375810a6-deed-4daf-ad42-a483b2c81804.htm 01-Sep-19
    API RP 2SIM 1ST ED (2014) Structural Integrity Management of Fixed Offshore Structures; First Edition This recommended practice provides guidance for the structural integrity management (SIM) of existing fixed offshore structures used for the drilling, development, production, and storage of hydrocarbons in offshore areas. However, the general principles of SIM apply to any structure.

    Specific guidance is provided for the evaluation of structural damage, above- and below-water structural inspection, fitness-for-purpose assessment, risk reduction, mitigation planning, and the process of decommissioning. This recommended practice incorporates and expands on the recommendations of Section 14, "Surveys" and Section 17, "Assessment of Existing Platforms" as previously provided in API 2A-WSD, 21st Edition. See Annex A for additional information and guidelines on the provisions stated in the numbered sections of this document.

    The SIM process provided in this recommended practice is applicable to existing platforms installed at any location worldwide. However, the recommended practice provides specific metocean criteria, which are only applicable for use in fitness-for-purpose assessments of platforms located in the U.S. Gulf of Mexico and the U.S. West Coast.

    For guidelines, recommended practices, and other requirements relating to planning, designing, and constructing new fixed offshore platforms, including reuse and change-in-use of existing platforms, reference should be made to the latest edition of API 2A-WSD.

    For guidelines, recommended practices, and other requirements relating to planning, designing, and constructing new offshore floating production systems, including reuse and change-in-use of existing floating production systems, reference should be made to the latest edition of API 2FPS.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e3b059d2-9476-43c4-8993-f48328420ac6.htm 01-Nov-14
    API RP 2SK 3RD ED (A1) (R 2015) Design and Analysis of Stationkeeping Systems for Floating Structures; Third Edition; Reaffirmed, June 2015 The purpose of this document is to present a rational method for analyzing, designing or evaluating station-keeping systems used for floating units. This method provides a uniform analysis tool which, when combined with an understanding of the environment at a particular location, the characteristics of the unit being moored, and other factors, can be used to determine the adequacy and safety of the mooring system. This document addresses station-keeping system (mooring, dynamic positioning, or thruster-assisted mooring) design, analysis, and operation. Different design requirements for mobile and permanent moorings are provided.

    The design procedure specified in this document is based on a deterministic approach where the mooring system responses such as line tensions, vessel offsets, and anchor loads are evaluated for a design environment defined by a return period. The mooring system responses are then checked against the mooring strength, offset limit, and anchor capacity to ensure a factor of safety against mooring breakage or excessive vessel excursion. It should be noted that mooring designs based on this approach may not have the same level of reliability, as discussed in Appendix G.

    The technology of mooring floating units is growing rapidly. In those areas where data considered adequate were available, specific and detailed recommendations are given. In other areas general statements are used to indicate that consideration should be given to those particular points. Designers are encouraged to utilize all research advances available to them. As offshore knowledge continues to grow, this document will be revised. It is hoped that the general statements contained herein will gradually be replaced by detailed recommendations.

    This document does not address mooring inspection/maintenance requirements and synthetic fiber rope mooring. These issues are addressed in the following API documents:

    • API RP 2I, Recommended Practice for In-Service Inspection of Mooring Hardware for Floating Drilling Units (Reference 1).

    • API RP 2SM, Recommended Practice for Design, Manufacturing, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring (Reference 2).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/5cb444db-c6f5-4b38-9684-eb25ff6f21b1.htm 01-Jun-15
    API RP 2SM 2ND ED (2014) Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring; Second Edition 1.1 This document applies to synthetic fiber ropes used in the form of taut leg or catenary moorings for both permanent and temporary offshore installations such as:

    a) monohull-based floating production, storage, and offloading units (FPSOs);

    b) monohull-based floating storage units (FSOs, FSUs);

    c) monohull or semi-submersible based floating production units (FPUs, FPSs);

    d) mobile offshore drilling units (MODUs);

    e) spar platforms;

    f) catenary anchor leg mooring (CALM) buoys (spread mooring only);

    g) mobile offshore units (MOUs, e.g., construction, pipelay, floating accommodation vessels).

    1.2 This document covers the following aspects of synthetic fiber ropes:

    a) design and analysis considerations of mooring system;

    b) design criteria for mooring components;

    c) rope design;

    d) rope specification and testing;

    e) rope manufacture and quality assurance;

    f) rope handling and installation;

    g) in-service inspection and maintenance.

    1.3 Application of this document to other offshore mooring applications is at the discretion of the designer and operator. This document is not intended to cover other marine applications of synthetic fiber ropes such as tanker mooring at piers and harbors, towing hawsers, mooring hawsers at single-point moorings (SPMs), and tension leg platform (TLP) tethers. Additionally, very little test data are available for large synthetic fiber ropes permanently deployed around fairleads and thus this document is limited to fiber ropes which span freely between end terminations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5a316b87-b516-4c2a-aa02-f26409b9d882.htm 01-Jul-14
    API RP 2T 3RD ED (R 2015) Planning, Designing, and Constructing Tension Leg Platforms; Third Edition; Reaffirmed, June 2015 This recommended practice is a guide to the designer in organizing an efficient approach to the design of a tension leg platform (TLP). Emphasis is placed on participation of all engineering disciplines during each stage of planning, development, design, construction, installation, and inspection.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/1d0a8cb8-6661-4fd7-9334-4cd1b5aa0709.htm 01-Jun-15
    API RP 2X 4TH ED (R 2015) Recommended Practice for Ultrasonic and Magnetic Examination of Offshore Structural Fabrication and Guidelines for Qualification of Technicians; Fourth Edition; Reaffirmed, June 2015 This recommended practice (RP) for nondestructive examination (NDE) of offshore structural fabrication and guidelines for qualification of personnel contains guidance on NDE methods which have evolved from fabrication experience with offshore structures. These methods are commonly used and have found acceptance due to their reliable detection of discontinuities. The five NDE methods routinely used in offshore structural fabrication are visual (VT), penetrant (PT), magnetic particle (MT), radiography (RT), and ultrasonic (UT) examinations. This recommended practice primarily addresses the MT and UT methods. Guidance on VT, PT and RT is incorporated by reference to ANSI/AWS D1.1. Further recommendations are offered for determining the qualifications of personnel using MT and UT techniques. Recommendations are also offered for the integration of these techniques into a general quality control program. The interrelationship between joint design, the significance of defects in welds, and the ability of NDE personnel to detect critical-size defects is also discussed.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/1554ae21-8818-4cf8-9693-fad3cc8664a5.htm 01-Jun-15
    API RP 2Z 4TH ED (R 2015) Recommended Practice for Preproduction Qualification for Steel Plates for Offshore Structures; Fourth Edition; Reaffirmed, June 2015 This Recommended Practice covers requirements for Preproduction qualification, by special welding and mechanical testing, of specific steelmaking and processing procedures for the manufacture of steel of a specified chemical composition range by a specific steel producer. This is a Recommended Practice for material selection and qualification, but not for the performance of production weld joints. This Recommended Practice was developed in conjunction with, and is intended primarily for use with, API Specifications 2W and 2Y. However, it may be sued as a supplement to other material specification s (e.g., API Specification 2H) if so desired.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c963fc04-24b3-42cd-a05f-69c268807e5c.htm 01-Jun-15
    API RP 31A 1ST ED (R 2012) Standard Form for Hardcopy Presentation of Downhole Well Log Data; First Edition; Reaffirmed, January 2012 The variety, use, and value of log recordings of subsurface properties have been greatly increased and expanded since the last revision of Recommended Practice 3 1. A wide diversity of log measurements (from both open and cased hole) are routinely being combined to interpret the original status of newly drilled wells and to evaluate performance and potential throughout each well's life. Standardization of the log form and data presentation will allow the user to conveniently combine log data from various devices and dates. Recognizing the wide variability in the tools covered by these recommendations, this document attempts to preserve flexibility wherever possible. The format selected allows for presentation of data that can be measured as a series of values at specified well depths. Consequently, this document can be easily applied to most logging measurements, and will serve as a reference document to technology-specific documents. This document makes no recommendations concerning the standard log record (refer to Section 4) for measurements that are data series at individual depths (for example, pressure transients, video images, sonic traces, and so forth). To the extent that recommended practices for the presentation of such data are appropriate, they should be included within separate Recommended Practices for the technologies involved.

    In addition to the recommendations concerning the format for presentation of log data, this document provides several enhancements to the standard log heading. These changes are designed to provide the user with a more complete set of information in consistent locations on all logs. Due to the increasing use of tool calibration and data processing while logging, recommendations are provided concerning documentation of equipment history and processing software. One should identify tool-specific information in other appropriate recommended publications.

    The recommended additions to the content of the support information included with hardcopy presentations of well log data, as described in the following, should also be included with digital recordings of the same well logs. The recommended digital formats to be used are provided in API Recommended Practice 66.

    The recommendations contained within API Recommended Practice 31A provide some flexibility regarding the dimensions of the actual print field used in the hardcopy presentation of well log data. This flexibility will accommodate the use of commonly available printers and paper sizes as optional alternatives to the 6.25-inch by 9.25-inch fanfold paper on which log data has been traditionally printed. Example figures conforming to this document and printed at the dimensions required for 8.5-inch by 11-inch paper are provided. The changes made to accommodate this flexibility in paper and printer selection will in no way alter the actual scaling sof the log data. Log data curves will precisely "overlay," regardless of the choice of paper or print field dimensions. Any hardcopy presentation of log data that meets all of the information content and format specifications described in the text of this document shall be considered to be in conformance with it.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8e86e6ad-07a1-4ced-a198-fbbe726d8599.htm 01-Jan-12
    API RP 41 2ND ED (R 2010) Recommended Practice for Presenting Performance Data on Cementing and Hydraulic Fracturing Equipment; Second Edition; Reaffirmed, September 2010 This standard provides a standard procedure for measuring, reporting, and

    certifying the hydraulic-horsepower rating of pumping units used in hydraulic fracturing and cementing services operations. The standard also establishes a recommended format for reporting the performance of such pumping units.

    This standard is applicable to any type of high pressure pumping unit, regardless of components such as prime movers, transmissions, and pumps.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/9b2ebbc5-d3d9-4235-bae8-308d312cee27.htm 01-Feb-95
    API RP 42 1ST ED (1962) Recommended Practice for Laboratory Testing and Field Data Analysis of Surface-Active Agent for Well Stimulation; 1st Edition The surfactant evaluation tests were complied by a task group of the API Southern District Study Committee on Well Stimulation with Surface-active Agents, of the Committees on Drilling and Production Practice, membership of which is given on the preceding pages. As defined by the committee, oil-well conditions which may be susceptible to surfactant treatment are the following:

    A.Fluid block, which may be corrected by:

    1. Reduction in water in saturation.

    2. Increased deformability (lower interfacial tension) of blocking droplets.

    3. Reduction in viscosity or breaking of emulsions.

    4. Alteration in gettability to redistribute fluid phases.

    B. Particle block (particularly clays), which may be corrected by:

    1. Reduction in amount of water associated with the particle.

    2. Removal or redistribution of the particles.

    b. The methods herein described are tentative, pending further evaluation and improvement. They represent procedures currently used in the laboratories of several major oil and service companies, and range in character from complex laboratory installations to simple qualitative tests capable of application in the oil field. It is conceded that information is generally lacking in the area of well stimulation, particularly as regards subsurface conditions. Accordingly, these tests are not represented as absolute methods for determining well-stimulation procedure. Rather, they are to be considered as an aid in comparing the many products currently available for well stimulation.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/57d0ed36-7d29-4a3e-85b8-fdbf431a31d3.htm 01-Nov-62
    API RP 42 2ND ED (R 1990) Recommended Practices for Laboratory Evaluation of Surface Active Agents for Well Stimulation; 2nd Edition A.Surface active agents are frequently added to treating fluids for stimulation of oil, gas, and injection wells to perform one or more of the following functions:

    1. Prevent or minimize emulsification of treating fluid with formation fluid,

    2. Reduce water saturation,

    3. Alter gettability,

    4. Suspend fine particles dislodged by the treatment for removal or redistribution, and

    5. Stabilize foam or emulsion in the treating fluid.

    B.The diversity of function has resulted in the availability of a large number of products for use in petroleum production operation. Testing of surface active agents as described herein is primarily for qualitative comparison of performance and for general screening related to preceding Paragraph A, items 1-4. Procedures are given for the following:

    1. emulsion and sludge tests,

    2. measurement of fluid flow through cores,

    3. Measurement of interfacial tension, and

    4 measurement of wettability

    C. Since chemical activity of a surface active agent (surfactant) depends on its chemical environment, pressure, temperature, and time, the user is advised to test the surface active agent in the presence of all additives to be used in a field treatment at their appropriate concentration. Production batch and shelf life may effect variation in surface active agents’ properties, so that in many cases even these items must be considered in evaluating a surface active agent.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/ec7d515d-6f68-40c6-821f-6bf83e8eebef.htm 01-Feb-90
    API RP 45 3RD ED (R 2012) Recommended Practice for Analysis of Oilfield Waters; Third Edition This document is directed toward the determination of dissolved and dispersed components in oilfield waters (produced

    water, injected water, aqueous work over fluids, and stimulation fluids). Bacterial analyses, bioassay (toxicity tests for marine animals), NORM determination, and membrane filter procedures are outside the scope of this document.

    Biological determination of the species and concentration of bacteria are covered in NACE TM0194-94, Field Monitoring of Bacterial Growth in Oilfield Systems. Determinations of Naturally Occurring Radioactive Materials (NORM) in oilfield waters is discussed in API Bulletin E2, Bulletin on Management of Naturally Occurring Radioactive Materials (NORM) in Oil and Gas Production.

    Membrane filter procedures are covered in NACE TM01- 73, Test Methods for Determining Water Quality for Subsurface Injection Using Membrane Filters.

    Analyses for residuals of proprietary organic treatment chemicals, such as corrosion inhibitors, demulsifiers, scale inhibitors, water clarifiers, biocides, etc. are also outside the scope of this document. However, analyses for generic components of proprietary chemicals, such as phosphate (scale inhibitor), are included in this document.

    Lastly, analyses of nonhazardous oilfield waste (NOW), such as drilling fluid, soil, cores, etc. are outside the scope of this document. However, analyses of separated water (including filtrates) from such sources are within the scope.

    The analytical methods presented in this document were selected for their accuracy, reproducibility, and applicability to oilfield systems. For most constituents, several methods of varying degrees of complexity and accuracy are presented to provide the analyst with the opportunity to choose the most appropriate and cost effective method pertinent to his/her needs.

    While the cited methods may also be used as indicators of the environmental quality of oilfield waters, regulatory agencies prescribe their own analytical methods that must be followed. These regulatory agencies should be consulted to obtain the relevant analytical procedures for cases in which data is to be used to verify environmental compliance.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/316e5b1d-59b4-468d-84d7-6eaf952e554c.htm 01-Aug-98
    API RP 4G 4TH ED (E1) Operation, Inspection, Maintenance, and Repair of Drilling and Well Servicing Structures; Fourth Edition This document provides guidelines and establishes recommended procedures for inspection, maintenance, and repair of items for drilling and well servicing structures, in order to maintain the serviceability of this equipment. The information in this document should be considered as supplemental to, and not as a substitute for, the manufacturer's instructions and the recommendations in API 54.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/a0ed9e52-c14c-459c-ba5c-f1c68549e573.htm 01-Sep-13
    API RP 4G 4TH ED (E1) (A1) Operation, Inspection, Maintenance, and Repair of Drilling and Well Servicing Structures; Fourth Edition This document provides guidelines and establishes recommended procedures for inspection, maintenance, and repair of items for drilling and well servicing structures, in order to maintain the serviceability of this equipment. The information in this document should be considered as supplemental to, and not as a substitute for, the manufacturer's instructions and the recommendations in API 54.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c9c5ea5c-96a8-4e02-87d1-429793b86535.htm 01-Aug-16
    API RP 4G 5TH ED (2019) Operation, Inspection, Maintenance, and Repair of Drilling and Well Servicing Structures; Fifth Edition This document provides guidelines and establishes recommended procedures for inspection, maintenance, and repair of items for drilling and well servicing structures, in order to maintain the serviceability of this equipment. The information in this document should be considered as supplemental to, and not as a substitute for, the manufacturer's instructions and the recommendations in API 54.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/dc487255-9598-4ca3-8596-f58fb16ddb5d.htm 01-Feb-19
    API RP 4G 5TH ED INSPECTION FORMS (2019) Inspection Forms for Operation, Inspection, Maintenance, and Repair of Drilling and Well Servicing Structures; Fifth Edition This document provides guidelines and establishes recommended procedures for inspection, maintenance, and repair of items for drilling and well servicing structures, in order to maintain the serviceability of this equipment. The information in this document should be considered as supplemental to, and not as a substitute for, the manufacturer's instructions and the recommendations in API 54.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b224eb5d-69a6-4042-a8ef-68617fb3b1af.htm 01-Feb-19
    API RP 50 2ND ED (R 2013) Natural Gas Processing Plant Practices for Protection of the Environment; Second Edition; Reaffirmed, January 2013 Operations within the scope of this standard include natural gas processing and associated gas compression facilities. The publication coverage begins with initial plant planning, permitting, and construction and ends with plant closure and site restoration procedures. General guidelines are provided to be used at gas plant locations to develop site-specific environmental programs.

    This standard does not address safety or operational issues except where environmental, safety, and operational issues are intertwined. Process design and equipment selection are not addressed in detail. This publication does not specifically address requirements of process safety management (refer to 29 CFR Part 1910.119) that must be considered in gas plant design and operations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9fef6501-35b6-48ea-b493-cd3bc93b63d3.htm 01-Dec-95
    API RP 51R 1ST ED (2009) Environmental Protection for Onshore Oil and Gas Production Operations and Leases; First Edition This standard provides environmentally sound practices for domestic onshore oil and gas production operations. It is intended to be applicable to contractors as well as operators. Facilities within the scope of this document include all production facilities, including produced water handling facilities. Offshore and arctic areas are beyond the scope of this document. Operational coverage begins with the design and construction of access roads and well locations, and includes reclamation, abandonment, and restoration operations. Gas compression for transmission purposes or production operations, such as gas lift, pressure maintenance, or enhanced oil recovery (EOR) is included; however, gas processing for liquids recovery is not addressed. Annex A provides guidance for a company to consider as a “good neighbor.”


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/468aa60f-2d1e-41c5-b7d8-2f2ca3986587.htm 01-Jul-09
    API RP 51R 1ST ED (R 2015) Environmental Protection for Onshore Oil and Gas Production Operations and Leases; First Edition; Reaffirmed, December 2015 This standard provides environmentally sound practices for domestic onshore

    oil and gas production operations. It is intended to be applicable to contractors as well as operators. Facilities within the scope of this document include all production facilities, including produced water handling facilities. Offshore and arctic areas are beyond the scope of this document. Operational coverage begins with the design and construction of access roads and well locations, and includes reclamation, abandonment, and restoration operations. Gas compression for transmission purposes or production operations, such as gas lift, pressure maintenance, or enhanced oil recovery (EOR) is included; however, gas processing for liquids recovery is not addressed. Annex A provides guidance for a company to consider as a “good neighbor.”


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/2ae2c35c-902e-4c39-b512-e2c1c1b843b0.htm 01-Jul-09
    API RP 52 2ND ED (1995) Land Drilling Practices for Protection of the Environment; Second Edition This standard provides information on environmentally sound practices for land drilling operations. Operational coverage begins with the initial planning of the drilling project and ends with decommissioning of the drill site. Facilities within the scope of this standard include the drill site and roads required to be built and used for access to the drill site.

    This document is intended to address environmental considerations and not safety or operational issues. However, there are items discussed, i.e., formation pressure control, for which there are mutual environmental, safety, and operational considerations. Similarly, this standard does not address obligations that may be required by the landowner and lease agreement.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/0a7ac515-0113-4fa4-9f72-94b34394c360.htm 01-Jul-95
    API RP 53 3RD ED (1997) Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells; Third Edition 1.1 PURPOSE

    The purpose of these recommended practices is to provide information that can serve as a guide for installation and testing of blowout prevention equipment systems on land and marine drilling rigs (barge, platform, bottom-supported, and floating). Blowout prevention equipment systems are composed of all systems required to operate the blowout preventers (BOPs) under varying rig and well conditions. These systems are: blowout preventers (BOPs), choke and kill lines, choke manifold, hydraulic control system, marine riser, and auxiliary equipment. 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 withdrawn from the wellbore. In addition, diverter systems are addressed in this Recommended Practice, though their primary purpose is to safely divert flow rather than to confine fluids to the wellbore. Refer to API Recommended Practice 64 for additional information on diverter systems. Marine risers are not dealt with in detail in this document. Refer to API Recommended Practice 16Q for additional information on marine drilling risers.

    1.2 WELL CONTROL

    Procedures and techniques for well control are not included in this publication since they are beyond the scope of equipment systems contained herein (refer to API Recommended Practice 59).

    1.3 BOP INSTALLATIONS

    In some instances, this publication contains a section pertaining to surface BOP installations followed by a section on subsea BOP installations. A delineation was made between surface and subsea equipment installations so these recommended practices would also have utility in floating drilling operations. Statements concerning surface equipment installations also generally apply to subsea equipment installations.

    1.4 EQUIPMENT ARRANGEMENTS

    Recommended equipment arrangements, as set forth in this publication, are adequate to meet specified well conditions. It is recognized that other arrangements may be equally effective and can be used in meeting well requirements and promoting safety and efficiency.

    1.5 LOW TEMPERATURE OPERATIONS

    Although operations are being conducted in areas of extremely low temperatures, a section specifically applicable to this service was not included since current practice generally results in protecting existing BOP equipment from this environment.

    1.6 IN-THE-FIELD CONTROL SYSTEM ACCUMULATOR CAPACITY

    It is important to distinguish between the standards for in-the-field control system accumulator capacity established here in Recommended Practice 53 and the design standards established in API Specification 16D.

    API Specification 16D provides sizing guidelines 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, 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 which is not actually intended to be usable to operate well control functions on the rig.

    For this reason, the control system design accumulator capacity formulas established in Specification 16D are different from the demonstrable capacity guidelines provided here in Recommended Practice 53.

    The original control system manufacturer shall be consulted in the event that the field calculations or field testing should indicate insufficient capacity or in the event that the volumetric requirements of equipment being controlled are changed, such as by the modification or changeout of the BOP stack.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/c270b267-3df1-4e41-a1ed-7332513c1509.htm 01-Mar-97
    API RP 53 3RD ED (R 2004) Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells; Third Edition; Reaffirmed, September 2004 1.1 PURPOSE

    The purpose of these recommended practices is to provide information that can serve as a guide for installation and testing of blowout prevention equipment systems on land and marine drilling rigs (barge, platform, bottom-supported, and floating). Blowout prevention equipment systems are composed of all systems required to operate the blowout preventers (BOPs) under varying rig and well conditions. These systems are: blowout preventers (BOPs), choke and kill lines, choke manifold, hydraulic control system, marine riser, and auxiliary equipment. 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 withdrawn from the wellbore. In addition, diverter systems are addressed in this Recommended Practice, though their primary purpose is to safely divert flow rather than to confine fluids to the wellbore. Refer to API Recommended Practice 64 for additional information on diverter systems. Marine risers are not dealt with in detail in this document. Refer to API Recommended Practice 16Q for additional information on marine drilling risers.

    1.2 WELL CONTROL

    Procedures and techniques for well control are not included in this publication since they are beyond the scope of equipment systems contained herein (refer to API Recommended Practice 59).

    1.3 BOP INSTALLATIONS

    In some instances, this publication contains a section pertaining to surface BOP installations followed by a section on subsea BOP installations. A delineation was made between surface and subsea equipment installations so these recommended practices would also have utility in floating drilling operations. Statements concerning surface equipment installations also generally apply to subsea equipment installations.

    1.4 EQUIPMENT ARRANGEMENTS

    Recommended equipment arrangements, as set forth in this publication, are adequate to meet specified well conditions. It is recognized that other arrangements may be equally effective and can be used in meeting well requirements and promoting safety and efficiency.

    1.5 LOW TEMPERATURE OPERATIONS

    Although operations are being conducted in areas of extremely low temperatures, a section specifically applicable to this service was not included since current practice generally results in protecting existing BOP equipment from this environment.

    1.6 IN-THE-FIELD CONTROL SYSTEM ACCUMULATOR CAPACITY

    It is important to distinguish between the standards for in-the-field control system accumulator capacity established here in Recommended Practice 53 and the design standards established in API Specification 16D.

    API Specification 16D provides sizing guidelines 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, 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 which is not actually intended to be usable to operate well control functions on the rig.

    For this reason, the control system design accumulator capacity formulas established in Specification 16D are different from the demonstrable capacity guidelines provided here in Recommended Practice 53.

    The original control system manufacturer shall be consulted in the event that the field calculations or field testing should indicate insufficient capacity or in the event that the volumetric requirements of equipment being controlled are changed, such as by the modification or changeout of the BOP stack.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/dcba5304-a482-4ed3-96d7-355eabc14175.htm 01-Mar-97
    API RP 59 2ND ED (2006) Recommended Practice for Well Control Operations; Second Edition The purpose of these recommended practices is to provide information that can serve as a voluntary industry guide for safe well control operations. This publication is designed to serve as a direct field aid in well control and as a technical source for teaching well control principles. This publication establishes recommended operations to retain pressure control of the well under pre-kick conditions and recommended practices to be utilized during a kick. It serves as a companion to API RP 53, Recommended Practice for Blowout Prevention Equipment Systems for Drilling Wells and API RP 64 Recommended Practice for Diverter Systems Equipment and Operations (reader should check for the latest edition). RP 53 establishes recommended practices for the installation and testing of equipment for the anticipated well conditions and service and RP 64 establishes recommended practices for installation, testing, and operation of diverters systems and discusses the special circumstances of uncontrolled flow from shallow gas formations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/72508ba3-cbd3-4d7a-8877-360305827b62.htm 01-May-06
    API RP 59 2ND ED (R 2012) Recommended Practice for Well Control Operations; Second Edition; Reaffirmed, January 2012 The purpose of these recommended practices is to provide information that can serve as a voluntary industry guide for safe well control operations. This publication is designed to serve as a direct field aid in well control and as a technical source for teaching well control principles. This publication establishes recommended operations to retain pressure control of the well under pre-kick conditions and recommended practices to be utilized during a kick. It serves as a companion to API RP 53, Recommended Practice for Blowout Prevention Equipment Systems for Drilling Wells and API RP 64 Recommended Practice for Diverter Systems Equipment and Operations (reader should check for the latest edition). RP 53 establishes recommended practices for the installation and testing of equipment for the anticipated well conditions and service and RP 64 establishes recommended practices for installation, testing, and operation of diverters systems and discusses the special circumstances of uncontrolled flow from shallow gas formations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/84ec539f-3a25-4b52-a6cd-23b9ab8fcbea.htm 01-May-06
    API RP 59 2ND ED (R 2018) Recommended Practice for Well Control Operations; Second Edition; Reaffirmed, December 2018 The purpose of these recommended practices is to provide

    information that can serve as a voluntary industry guide for safe well control operations. This publication is designed to serve as a direct field aid in well control and as a technical source for teaching well control principles. This publication establishes recommended operations to retain pressure control of the well under pre-kick conditions and recommended practices to be utilized during a kick. It serves as a companion to API RP 53, Recommended Practice for Blowout Prevention Equipment Systems for Drilling Wells and API RP 64 Recommended Practice for Diverter Systems Equipment and Operations (reader should check for the latest edition). RP 53 establishes recommended practices for the installation and testing of equipment for the anticipated well conditions and service and RP 64 establishes recommended practices for installation, testing, and operation of diverters systems and discusses the special circumstances of uncontrolled flow from shallow gas formations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6a884294-b41c-41a6-ae4e-6787c9114155.htm 01-May-06
    API RP 5A3 3RD ED (E1) (R 2015) Recommended Practice on Thread Compounds for Casing, Tubing, Line Pipe, and Drill Stem Elements; Third Edition; Reaffirmed, April 2015; ISO 13678:2010 This International Standard provides requirements, recommendations and methods for the testing of thread compounds intended for use on threaded casing, tubing, and line pipe connections; and for thread compounds intended for use on rotary shouldered connections. The tests outlined are used to evaluate the critical performance properties and physical and chemical characteristics of thread compounds under laboratory conditions.

    These test methods are primarily intended for thread compounds formulated with a lubricating base grease and are not applicable to some materials used for lubricating and/or sealing thread connections. It is recognized that many areas can have environmental requirements for products of this type. This International Standard does not include requirements for environmental compliance. It is the responsibility of the end user to investigate these requirements and to select, use and dispose of the thread compounds and related waste materials accordingly.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/637693de-ea6b-4ffe-a711-4b7e69185b15.htm 01-Apr-15
    API RP 5A5 7TH ED (E1) (R 2015) Field Inspection of New Casing, Tubing, and Plain-end Drill Pipe; Seventh Edition; Reaffirmed, April 2015; ISO 15463:2003 This International Standard specifies requirements and gives recommendations for field inspection and testing of oil country tubular goods (OCTG). This International Standard covers the practices and technology commonly used in field inspection; however, certain practices may also be suitable for mill inspections.

    This International Standard covers the qualification of inspection personnel, a description of inspection methods and apparatus calibration and standardization procedures for various inspection methods. The evaluation of imperfections and marking of inspected OCTG are included.

    This International Standard is applicable to field inspection of OCTG and is not applicable for use as a basis for acceptance or rejection (for which the relevant purchasing specification is applicable, see 5.4.2).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/2da7db8b-27d9-48be-a0b6-34220f5d1edf.htm 01-Apr-15
    API RP 5B1 5TH ED (R 2015) Gauging and Inspection of Casing, Tubing, and Line Pipe Threads; Fifth Edition; Reaffirmed, May 2015 Information contained in this recommended practice is intended for use of pipe manufacturer inspectors, quality control personnel, field inspectors, threading unit operators, and users and purchasers of oil country tubular goods and line pipe.

    This publication was prepared under the auspices of the API Subcommittee of Tubular Goods and the Resource Group on Threading and Gauging. As such, the scope is limited to inspection of API casing, tubing, and line pipe connections. However, the basic techniques of gauge usage apply to any threads for which the thread element specifications are known. Specifically, this recommended practice was written to supplement and augment the latest editions of API Specifications 5CT and 5L, which mandate physical and mechanical properties of casing, tubing, and line pipe. Additionally, this recommended practice is designed to be used with the latest edition of API Specification 5B, Specification for Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads. It does not duplicate the massive dimensional tables contained in the latest edition of API Spec 5B. Instead, it provides instruction in inspection techniques appropriate to comparing the dimension of the product with specified dimensions and tolerances for that product. Accordingly, the primer can be used for the inspection of API thread elements without direct reference to the latest edition of Spec 5B. In all cases, the latest edition of Spec 5B takes precedence if a dispute arises between parties.

    This publication uses photographs to demonstrate the proper use of representative gauges normally used by thread inspectors. Gauges presented are limited to those appropriate to both mill and field use. Thus, nonportable instruments such as comparators and contour readers are not included. However, there is no intent to limit the use of such instruments or methods by inspectors.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0e613e51-7a73-4804-bd8b-f3859541fe57.htm 01-May-15
    API RP 5C1 18TH ED (R 2015) Recommended Practice for Care and Use of Casing and Tubing; Eighteenth Edition; Reaffirmed, May 2015 Note: No provision of this recommended practice shall be cause for rejection of casing or tubing provided the threads are in accordance with the requirements of the latest edition of API Standard 5B.

    1.1The statements on corrosion of casing and tubing as given herein were developed with the cooperation of the Technical Practices Committee on Corrosion of Oil and Gas Well Equipment, NACE International (formerly the National Association of Corrosion Engineers).

    1.2It is suggested that the selection of a thread compound for casing and tubing be given careful consideration by the user, bearing in mind that a satisfactory compound should possess certain properties, the major of which are (a) to lubricate the thread surfaces to facilitate joint makeup and breakout without galling, and (b) to seal voids between the mating thread surfaces and effectively prevent leakage. Compounds that have given outstanding service for casing and tubing under both laboratory and field conditions are described in the latest edition of API Bulletin 5A2.

    Note: Thread compounds described in the latest edition of API Bulletin 5A2 should not be used on rotary shouldered connections.

    1.3Some generalized suggestions on prevention of damage to casing and tubing by corrosive fluids are given in 4.8.16 and 5.5.15. It is not, however, within the scope of this recommended practice to provide detailed suggestions for corrosion control under specific conditions. Many variables may be involved in a specific corrosion problem and interrelated in such a complex fashion as to require detailed attention to the specific problem. For more complete technical information on specific corrosion problems, the user should consult the official publication of NACE International, Corrosion, or contact: Chairman, Technical Practices Committee on Corrosion of Oil and Gas Well Equipment, T-1, NACE Int'l, 1440 South Creek Drive, P.O. Box 218340, Houston, Texas 77218- 8340.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/84ba0131-f850-4c7d-8de8-2a3a14c8a02c.htm 01-May-15
    API RP 5C5 3RD ED (R 2015) Recommended Practice on Procedures for Testing Casing and Tubing Connections; Third Edition; Reaffirmed, April 2015; ISO 13679:2002 This International Standard establishes minimum design verification testing procedures and acceptance criteria for casing and tubing connections for the oil and natural gas industries. These physical tests are part of a design verification process and provide objective evidence that the connection conforms to the manufacturer's claimed test load envelope and limit loads.

    It categorizes test severity into four test classes.

    It describes a system of identification codes for connections.

    This International Standard does not provide the statistical basis for risk analysis.

    This International Standard addresses only three of the five distinct types of primary loads to which casing and tubing strings are subjected in wells: fluid pressure (internal and/or external), axial force (tension or compression), bending (buckling and/or wellbore deviation), as well as make-up torsion. It does not address rotation torsion and non-axisymetric (area, line or point contact) loads.

    This International Standard specifies tests to be performed to determine the galling tendency, sealing performance and structural integrity of casing and tubing connections. The words casing and tubing apply to the service application and not to the diameter of the pipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/57e08ae5-90e8-4455-b41b-b4ca83da621e.htm 01-Apr-15
    API RP 5C5 4TH ED (2017) Recommended Practice on Procedures for Testing Casing and Tubing Connections; Third Edition; Reaffirmed, April 2015 This Recommended Practice (RP) defines tests to determine the galling tendency, sealing performance, and structural integrity of threaded casing and tubing connections. The words “casing” and “tubing” apply to the service application and not to the diameter of the pipe. This RP addresses the primary loads to which casing and tubing strings are subjected: fluid pressure (internal and/or external), axial force (tension and/or compression), bending (buckling and/or wellbore deviation), and temperature variations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/61e7f18d-d4e4-4c49-b73b-3944a416b851.htm 01-Jan-17
    API RP 5C6 2ND ED (R 2012) Welding Connections to Pipe; Second Edition; Reaffirmed, September 2012 1.1 PURPOSE

    This recommended practice was created to provide a standard industry practice for the shop or field welding of connectors to pipe.

    The technical content provides requirements for welding procedure qualification, welder performance qualification, materials, testing, production welding and inspection. Additionally, suggestions for ordering are included.

    1.2 EQUIPMENT

    This recommended practice covers the weld fabrication of connectors and handling attachments such as lift eyes and landing pads to pipe.

    This document includes practices currently being implemented by a broad spectrum of the industry. This recommended practice is intended to be analogous to API 6A PSL 1 with additional requirements specific to the equipment fabrication.

    1.3 SUPPLEMENTAL REQUIREMENTS

    Supplements to this recommended practice shall not be considered as requirements except when specified on the purchase order.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/462b5ce0-f8aa-4795-88de-8996bd87a400.htm 01-Sep-12
    API RP 5C6 3RD ED (2018) Welding Connections to Pipe; Third Edition 1.1 Purpose

    This standard provides a practice for facility or field welding of connectors to pipe. The technical content contains guidance and requirements for welding procedure qualification, welder performance qualification, materials, testing, production welding, and inspection.

    1.2 Coverage

    This standard covers the weld fabrication of connectors and handling attachments, such as lift eyes and landing pads, to pipe. This standard also includes practices used within industry and is intended to be analogous to API 6A PSL 1 with additional requirements specific to the equipment fabrication.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0f5c7fee-fb9a-44c7-bf1d-e55e5b603f28.htm 01-May-18
    API RP 5C8 1ST ED (2017) Care, Maintenance, and Inspection of Coiled Tubing; First Edition This recommended practice covers the care, maintenance, and inspection of used low alloy carbon steel coiled tubing. Commonly manufactured coiled tubing outside diameters range from 25.4 mm (1.000 in.) to 88.9 mm (3.5 in.).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/251634b0-d25e-4ef9-b976-6b622c33f529.htm 31-Dec-16
    API RP 5EX 1ST ED (2018) Design, Verification, and Application of Solid Expandable Systems; First Edition This recommended practice establishes guidance for design, system verification, and application guidelines of solid expandable systems for the oil and gas industries. This document is not to be used as a specification for purchasing equipment; it is intended for consideration by users for well applications and the design of solid expandable systems.

    Expandable systems will include drilling liners, hangers, connections, receivers, and launchers for downhole use as defined herein. Only permanently installed equipment/components are covered by this recommended practice. Slotted liners and tools used for the expansion of the tubular goods (such as, but not limited to, implementation tools, pumps, jacks, and expansion tools) are not addressed by this recommended practice.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/80389ec3-b9b4-43b2-b108-f014927099c4.htm 01-May-18
    API RP 5L1 7TH ED (R 2015) Recommended Practice for Railroad Transportation of Line Pipe; Seventh Edition; Reaffirmed, May 2015 1.1 General

    The recommendations provided herein apply to the transportation on railcars of API 5L steel line pipe in sizes 2 3/8 and larger in lengths longer than single random. These recommendations cover coated or uncoated pipe, but they do not encompass loading practices designed to protect pipe coating from damage.

    1.2 Basic Rules and Requirements

    Certain minimum mandatory rules governing the loading practices are prescribed by the Association of American Railroads (AAR) as referenced in the next section.

    The recommendations given herein are supplementary to the AAR loading practices. If any recommendations are in conflict with AAR loading practices, those of AAR shall govern.

    NOTE If the AAR loading rules are not applicable to the railroad transportation of line pipe in the country of origin, the basic loading practice shall be as prescribed in the applicable nationally recognized loading rules and requirements for the type of railroad cars used in the country of origin and that document becomes the reference to which these supplementary recommendations apply.

    These supplementary recommendations to AAR rules are for the convenience of purchasers and manufacturers in the loading and shipping of pipe and are not intended to inhibit purchasers and manufacturers from using other supplementary loading and shipping practices by mutual agreement.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0f2ec808-17f6-4002-97f1-3c6f478af471.htm 01-May-15
    API RP 5L2 4TH ED (R 2015) Recommended Practice for Internal Coating of Line Pipe for Non-corrosive Gas Transmission Service; Fourth Edition; Reaffirmed, May 2015 This Recommended Practice provides for the internal coating of line pipe used for non-corrosive natural gas service. The recommendations provided herein cover:

    a. Section 1 Scope

    b. Section 2 Coating Material Specification

    c. Section 3 Laboratory Coating Testing

    d. Section 4 Application Practices

    e. Section 5 Production Inspection and Acceptance

    The Recommendation is limited to the application of internal coatings on new pipe prior to installation.

    It is intended that the applicator be responsible for complying with all of the provisions of this Recommended Practice, but that the Purchaser may make any investigation necessary to satisfy himself of compliance by the applicator.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8a63982b-9752-4371-bb98-b2459a766731.htm 01-May-15
    API RP 5L3 4TH ED (2014) Drop-Weight Tear Tests on Line Pipe; Fourth Edition These procedures describe a recommended method for conducting Drop-Weight Tear Tests to measure the fracture appearance or fracture ductility of the pipe as referenced in API Specification 5L, Specification for Line Pipe.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c3c7a299-65f5-445c-b9c5-53544ac0553b.htm 01-Aug-14
    API RP 5L7 2ND ED (R 2015) Recommended Practice for Unprimed Internal Fusion Bonded Epoxy Coating of Line Pipe; Second Edition; Reaffirmed, May 2015 This Recommended Practice provides for unprimed internal fusion bonded epoxy coating of line pipe for use in transportation pipelines in the petroleum industry.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/70897c34-3946-4411-8983-51a6389c0c56.htm 01-May-15
    API RP 5L8 2ND ED (R 2015) Recommended Practice for Field Inspection of New Line Pipe; Second Edition; Reaffirmed, May 2015 1.1 BASIS FOR INSPECTION

    This document contains practices recommended for use in the inspection of new line pipe subsequent to production by the manufacturer. Appendix A contains ordering information for owners desiring to order inspection of new pipe per this document. The basis for performing an inspection may have its origin either in API Specification 5L or in a supplemental specification or contract prepared by the owner. The inspections represented by the practices may be placed in one of three categories as follows:

    a. Inspections specified in API Specification 5L.

    b. Inspections specified as one of several options in API Specification 5L.

    c. Inspections not specified in API Specification 5L.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/6267551c-05bd-46b9-986f-b11f938a353b.htm 01-May-15
    API RP 5L9 1ST ED (R 2015) External Fusion Bonded Epoxy Coating of Line Pipe; First Edition; Reaffirmed, May 2015 1.1 DESCRIPTION

    This recommended practice provides external fusion bonded epoxy coating of line pipe for use in transportation pipelines. The Recommended Practice is limited to the application of external coatings on pipe prior to installation. There may exist differences in the surface condition of pipes produced by the various pipe making processes permitted under the latest editions of API standards. Surface conditions may preclude the coating of such pipe.

    The applicator shall be responsible for assuring compliance with all of the provisions of this practice however, the Purchaser may make any investigation necessary to satisfy himself of compliance by the applicator.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/cd017a70-17da-4004-80f7-0b5ee9b83bbe.htm 01-May-15
    API RP 5LT 1ST ED (2012) Recommended Practice for Truck Transportation of Line Pipe; First Edition The recommendations provided herein apply to the transportation of coated or bare line pipe in sizes 2 3/8 in. (60.3 mm) and larger, on trailer.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/28d56d32-b3d7-44e3-8d99-8638e87c664e.htm 01-Mar-12
    API RP 5LT 1ST ED (R 2019) Recommended Practice for Truck Transportation of Line Pipe; First Edition; Reaffirmed February 2019 The recommendations provided herein apply to the transportation of coated or bare line pipe in sizes 2 3/8 in. (60.3 mm) and larger, on trailer.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6442c391-ede7-4def-ab26-c32fbf83abd5.htm 01-Mar-12
    API RP 5LW 3RD ED (R 2015) Recommended Practice for Transportation of Line Pipe on Barges and Marine Vessels; Third Edition; Reaffirmed, May 2015 The recommendations in this document apply to transportation of API Specification 5L steel line pipe by ship or barge on both inland and marine waterways, unless the specific requirement of a paragraph in this document references only marine or only inland waterway transport. Inland waterways are defined as those waterways with various degrees of protection, such as rivers, canals, intracoastal waterways, and sheltered bays. These waterways can be fresh or saltwater but are usually traversed by barges. Marine waterways are defined as waterways over open seas with limited or no protection from wind, current, waves, and the like. These areas are normally traversed by sea-going vessels. These recommendations apply to steel line pipe that has 2 (3/8)-in. outside diameter (OD) and larger.

    These recommendations cover coated or uncoated pipe, but they do not encompass loading practices designed to protect pipe coating from damage. These recommendations are not applicable to pipe-laying vessels or supply vessels. They must be considered as supplementary to the existing rules of governing agencies.

    These recommendations are supplemental to shipping rules for the convenience of purchasers and manufacturers in the specification of loading and shipping practices and are not intended to inhibit purchasers and manufacturers from using other supplemental loading and shipping practices by mutual agreement.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/24cc19f8-deaa-4afd-9096-c11280997f26.htm 01-May-15
    API RP 5SI 1ST ED (R 2012) Recommended Practice for Purchaser Representative Surveillance and/or Inspection at the Supplier; First Edition; Reaffirmed, September 2012 1.1 PURPOSE AND COVERAGE

    The purpose of this Recommended Practice (RP) is to provide guidelines for the surveillance and/or inspection of API products at supplier locations. This Recommended Practice establishes a set of general guidelines addressing the protocol between purchasers, suppliers and the purchaser representative for surveillance and/or inspection by the purchaser representative. This Recommended Practice is a general document for use at the request of the purchaser of API products. This document is intended to provide only general guidance to the industry. The issue of the roles and responsibilities of the parties is a subject that should be addressed as part of negotiations between the purchaser and the supplier.

    Included as a part of this document are product specific appendices. Processes other than those included will be considered for inclusion in this Recommended Practice. Persons desiring to have other processes considered shall submit a request to the "Committee on Standardization of Tubular Goods."

    This Recommended Practice addresses the relationship and responsibility of the purchaser, suppliers, and purchaser representatives regarding surveillance and/or inspection of products from placement of the order or the pre-production meeting, as appropriate, through the point of title transfer from suppliers to purchasers. The use of the document by the parties is voluntary and it is merely intended to provide general guidelines on issues that should be addressed by the parties. This may include activities such as laboratory testing, nondestructive testing, dimensional verification, coating, shipping, handling/storage or other related activities.

    This RP is not intended to conflict with those inspection activities outlined in other API documents. In case of a conflict, the other applicable API Document shall prevail.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/4c8699d6-8557-4e3d-91eb-25a278036f62.htm 01-Sep-12
    API RP 5UE 2ND ED (R 2015) Recommended Practice for Ultrasonic Evaluation of Pipe Imperfections; Second Edition; Reaffirmed, May 2015 1.1 This recommended practice describes procedures which may be used to "prove-up" the depth or size of imperfections. Included in this practice are the recommended procedures for ultrasonic prove-up inspection of new pipe using the Amplitude Comparison Technique and the Amplitude Distance Differential Technique for evaluation of 1) surface breaking imperfections in the body of pipe and 2) surface breaking and subsurface imperfections in the weld area of electric resistance, electric induction or laser welded pipe and 3) surface breaking and subsurface imperfections in the weld area of arc welded pipe. For the purpose of this document, pipe is defined as including casing, plain-end casing liners, tubing, plain-end drill pipe, line pipe, coiled line pipe, pup joints, coupling stock, and connector material

    1.2

    Prove-up inspection is a method to evaluate the radial depth of imperfections detected by automated inspection equipment or other nondestructive testing (NDT) technique(s) to determine acceptance criteria compliance with the appropriate API specification.

    1.3The recommended prove-up practices established within this document are intended as a guide, and nothing in this guide should be interpreted to prohibit the agency or owner from supplementing the guide with other techniques or extending existing techniques.

    1.4

    This RP covers evaluation, a description of inspection methods, calibration and standardization procedures, and inspection personnel requirements for prove-up.

    1.5

    Appendix A of this document is provided as an overview to inform the user of the basis for the techniques outlined in this RP.

    1.6

    Appendix B of this document provides a procedure for determining if imperfections are surface breaking and a formula for calculating the sound path distance for a circumferential or axial scan of a curved surface and a sample look-up table.

    1.7

    Appendix C of this document is provided as an overview to inform the user of the specifics for the evaluation of welds with filler metal.

    1.8

    Appendix D of this document provides a procedure for sizing planar non-surface breaking imperfections from the pipe's outside surface.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/4fc9d25e-9bb2-4ff5-ae16-77ad6d50fab8.htm 01-May-15
    API RP 64 2ND ED (R 2007) Recommended Practice for Diverter Systems Equipment and Operations; Second Edition; Reaffirmed, March 1, 2007 This recommended practice (RP) is intended to provide accurate information that can serve as a guide for selection, installation, testing, and operation of diverter equipment systems on land and marine drilling rigs (barge, platform, bottom-supported, and floating). Diverter systems are composed of all subsystems required to operate the diverter under varying rig and well conditions. A general description of operational procedures is presented with suggestions for the training of rig personnel in the proper use, care, and maintenance of diverter systems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/9427ba17-3d7c-4dec-a272-fac305de3719.htm 01-Nov-01
    API RP 64 2ND ED (R 2012) Recommended Practice for Diverter Systems Equipment and Operations; Second Edition; Reaffirmed, January 2012 This recommended practice (RP) is intended to provide

    accurate information that can serve as a guide for selection, installation, testing, and operation of diverter equipment systems on land and marine drilling rigs (barge, platform, bottom-supported, and floating). Diverter systems are composed of all subsystems required to operate the diverter under varying rig and well conditions. A general description of operational procedures is presented with suggestions for the training of rig personnel in the proper use, care, and maintenance of diverter systems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/89a61511-cce8-44be-a78f-05d6908df222.htm 01-Nov-01
    API RP 65 1ST ED (E1) Cementing Shallow Water Flow Zones in Deepwater Wells; First Edition; Errata, August 2003 This document is the compilation of technology and practices used by many operators drilling wells in deep water. In a number of cases, there is not a single way of performing a specific operation. In some cases, several options may be listed, but in others there may be practices which are successful, but which are not listed in this document. This document is not meant to limit innovation.

    In wells drilled in deep ocean waters, water flows from shallow formations can compromise the hydraulic integrity of the tophole section. Modes of failure include: (1) poor isolation by cement resulting in casing buckling/shear; (2) pressure communication to other shallow formations causing them to be overpressured; and (3) disturbance of the seafloor due to breakthrough of the shallow flow to the mudline. Such damage can and has resulted in the complete loss of drilling templates containing previously cased wells. Additionally, such shallow flow can result in changes in the state of stress in the tophole section, possibly resulting to damage to existing casings in the present or adjacent wells later in the life of the well.

    Flows from these shallow formations are frequently a result of abnormally high pore pressure resulting from under-compacted and over-pressured sands caused by rapid deposition. Not all flows are the result of these naturally developed formation geo-pressures. Hydraulic communication with deeper, higher pressure formations is another cause for abnormal shallow pressures. Some of the observed shallow flow problems have been due to destabilization of gas hydrates or induced storage during drilling and casing and cementing operations. Although minor compared to geo-pressured sands, flows due to induced storage may still cause damage from sediment erosion or mining, breakthrough to adjacent wells and damage to the cement before it sets. These problems can worsen with each additional well when batch setting shallow casings. Although most of the discussion in this text is focused on shallow water flow (SWF), shallow flows can be mixtures of water, gas and formation fines. In most cases the concepts are similar and can be employed with minor modifications, depending on the type of flow.

    Flows allow production of sand and sediments resulting in hole enlargement which can increase the flow potential and make it more difficult to control. The enlargement may also cause caving of formations above the flow interval. The flow of water and formation material from these zones can result in damage to the wells including foundation failure, formation compaction, damaged casing (wear and buckling), reentry and control problems and sea floor craters, mounds and crevasses (OTC 11972, IADC/SPE 52780).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/930dd5fd-c206-4a4a-a3d3-61a9f141762e.htm 01-Sep-02
    API RP 65 1ST ED (E1) (R 2012) Cementing Shallow Water Flow Zones in Deepwater Wells; First Edition; Reaffirmed, January 2012 This document is the compilation of technology and practices

    used by many operators drilling wells in deep water. In a number of cases, there is not a single way of performing a specific operation. In some cases, several options may be listed, but in others there may be practices which are successful, but which are not listed in this document. This document is not meant to limit innovation.

    In wells drilled in deep ocean waters, water flows from shallow formations can compromise the hydraulic integrity of the tophole section. Modes of failure include: (1) poor isolation by cement resulting in casing buckling/shear; (2) pressure communication to other shallow formations causing them to be overpressured; and (3) disturbance of the seafloor due to breakthrough of the shallow flow to the mudline. Such damage can and has resulted in the complete loss of drilling templates containing previously cased wells. Additionally, such shallow flow can result in changes in the state of stress in the tophole section, possibly resulting to damage to existing casings in the present or adjacent wells later in the life of the well.

    Flows from these shallow formations are frequently a result of abnormally high pore pressure resulting from under-compacted and over-pressured sands caused by rapid deposition. Not all flows are the result of these naturally developed formation geo-pressures. Hydraulic communication with deeper, higher pressure formations is another cause for abnormal shallow pressures. Some of the observed shallow flow problems have been due to destabilization of gas hydrates or induced storage during drilling and casing and cementing operations. Although minor compared to geo-pressured sands, flows due to induced storage may still cause damage from sediment erosion or mining, breakthrough to adjacent wells and damage to the cement before it sets. These problems can worsen with each additional well when batch setting shallow casings. Although most of the discussion in this text is focused on shallow water flow (SWF), shallow flows can be mixtures of water, gas and formation fines. In most cases the concepts are similar and can be employed with minor modifications, depending on the type of flow.

    Flows allow production of sand and sediments resulting in hole enlargement which can increase the flow potential and make it more difficult to control. The enlargement may also cause caving of formations above the flow interval. The flow of water and formation material from these zones can result in damage to the wells including foundation failure, formation compaction, damaged casing (wear and buckling), reentry and control problems and sea floor craters, mounds and crevasses (OTC 11972, IADC/SPE 52780).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/0f79aabf-a217-4588-ac4b-e1a1c7754886.htm 01-Sep-02
    API RP 65-1 2ND ED (2018) Cementing Shallow-water Flow Zones in Deepwater Wells; Second Edition This standard describes practices designed to prevent shallow-water flow (SWF) during and following the cementing of wells located in deepwater. It is the compilation of technology and practices developed and used by many operators around the world. Although most of the discussion in this standard is focused on SWF, shallow flows can be mixtures of water, gas, gas hydrates, and formation fines. There is no single method of preventing shallow-water flow, and many of the activities described may require customization to fit individual well conditions. While this standard is extensive, it is not meant to limit innovation and new technology.

    The content of this document is not all inclusive, and guidance from other sources may apply. Note that this standard is not meant to be a stand-alone training manual or well design standard. Although fairly comprehensive, there are still many details that are not discussed and that should be addressed when drilling and cementing wells in deepwater. It is meant to highlight key parameters for increasing the chance of successfully drilling and cementing casings where there is a risk of shallow-water flow and to discuss options that are available. More details can be gleaned from the references listed in the bibliography. Most of the information in this document is from U.S. Gulf of Mexico experience. The concepts can be applied in other deepwater environments with appropriate modifications. The user should consult experts within the industry for specific details of the cementing process relating to the technology being used by a specific company for a specific scenario. The construction of the casings through the SWF zones should be a team effort to be successful. All parties involved shall participate in the planning and execution of all phases of the process to ensure successful construction of the conductor and surface casings.

    In this standard, where practical, U.S. customary units (USC) are included in parentheses for information. The units do not necessarily represent a direct conversion of metric units (SI) to USC units, or USC to SI. Consideration has been given to the precision of the instrument making the measurement. For example, thermometers are typically marked in one-degree increments; thus, temperature values have been rounded to the nearest degree.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/63d9a90d-a57d-455b-ad6b-9447b2a57da4.htm 01-Jun-18
    API RP 66 2ND ED (1996) Recommended Practices for Exploration and Production Data Digital Interchange; Second Edition 1.2 This document is intended to:

    a. Facilitate the development of exchange standards based on the API Recommended Practice 66, Version 2 format.

    b. Facilitate the development of schema-neutral software products and services, by promoting uniformity between API Recommended Practice 66, Version 2-based exchange standards.

    c. Promote compatibility between editions of a schema.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/371d212f-2a6f-42e3-8fea-5d68fbd67eaa.htm 01-Jun-96
    API RP 6DR 2ND ED (2012) Recommended Practice for the Repair and Remanufacture of Pipeline Valves; Second Edition This recommended practice provides guidelines for the repair and remanufacture of steel ball, check, gate, and plug valves normally used in pipeline applications, as defined by API 6D.

    This recommended practice covers repair or remanufacturing of end user’s (owner’s) valves for continued service in the owner’s production applications. It does not cover repair or remanufacture of used or surplus valves intended for resale.

    Repaired or remanufactured valves may not meet API 6D and/or the OEM original product definition (OPD) for new valves.

    The owner is responsible for the correct application of valves repaired or remanufactured per this document.

    Field repair is outside the scope of this document.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/70851380-8fae-4806-9a2c-3eb720886565.htm 01-May-12
    API RP 6DR 2ND ED (R 2020) Recommended Practice for the Repair and Remanufacture of Pipeline Valves; Second Edition; Reaffirmed: January 2020 This recommended practice provides guidelines for the repair and remanufacture of steel ball, check, gate, and plug valves normally used in pipeline applications, as defined by API 6D.

    This recommended practice covers repair or remanufacturing of end user’s (owner’s) valves for continued service in the owner’s production applications. It does not cover repair or remanufacture of used or surplus valves intended for resale.

    Repaired or remanufactured valves may not meet API 6D and/or the OEM original product definition (OPD) for new valves.

    The owner is responsible for the correct application of valves repaired or remanufactured per this document.

    Field repair is outside the scope of this document.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a7a3800a-34c6-488b-ad47-b4a4a8c73d68.htm 01-May-12
    API RP 6HT 2ND ED (2013) Heat Treatment and Testing of Carbon and Low Alloy Steel Large Cross Section and Critical Section Components; Second Edition This recommended practice (RP) may supplement the API equipment specifications for carbon and low alloy steel large cross section and critical components. The recommend practice described herein suggests the requirements for batch-type bath quench and water spray quench-type heat treating practices.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d678aeb5-1235-4af1-9d16-1394d86c3c09.htm 01-Jun-13
    API RP 6HT 2ND ED (R 2018) Heat Treatment and Testing of Carbon and Low Alloy Steel Large Cross Section and Critical Section Components; Second Edition; Reaffirmed, November 2018 This recommended practice (RP) may supplement the API equipment specifications for carbon and low alloy steel large cross section and critical components. The recommend practice described herein suggests the requirements for batch-type bath quench and water spray quench-type heat treating practices.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/31011cc5-978e-47ba-a79f-150c4d46f3ce.htm 01-Jun-13
    API RP 70 1ST ED (R 2010) Security for Offshore Oil and Natural Gas Operations; First Edition; Reaffirmed, September 2010 This publication is intended to assist the offshore oil and natural gas drilling and producing operators and contractors in assessing security needs during the performance of oil and natural gas operations. The offshore oil and natural gas industry uses a wide variety of contractors in drilling, production, and construction activities. Contractors typically are in one of the following categories: drilling, workover, well servicing, construction, electrical, mechanical, transportation, painting, operating, and catering/janitorial.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/67e5a1c9-a4a1-44d5-8d8c-819f049dfb1c.htm 01-Mar-03
    API RP 70I 1ST ED (2004) Security for Worldwide Offshore Oil and Natural Gas Operations; First Edition This publication is intended to assist the offshore oil and natural gas drilling and producing operators and contractors in assessing security needs during the performance of oil and natural gas operations. The offshore oil and natural gas industry uses a wide variety of contractors in drilling, production, and construction activities. Contractors typically are in one of the following categories: drilling, workover, well servicing, construction, electrical, mechanical, transportation, painting, operating, and catering/janitorial.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/4d0208bc-f3aa-403c-a614-d5b2410681cc.htm 01-May-04
    API RP 70I 1ST ED (R 2012) Security for Worldwide Offshore Oil and Natural Gas Operations; First Edition; Reaffirmed, January 2012 This publication is intended to assist the offshore oil and natural gas drilling and producing operators and contractors in assessing security needs during the performance of oil and natural gas operations. The offshore oil and natural gas industry uses a wide variety of contractors in drilling, production, and construction activities. Contractors typically are in one of the following categories: drilling, workover, well servicing, construction, electrical, mechanical, transportation, painting, operating, and catering/janitorial.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/cec1a1e0-7020-4413-882f-ed6365149f2d.htm 01-May-04
    API RP 75 3RD ED (R 2008) Recommended Practice for Development of a Safety and Environmental Management Program for Offshore Operations and Facilities; Third Edition; Reaffirmed, May 2008 1.3.1.1 This recommended practice is intended for application to offshore oil, gas, and sulphur facilities and associated equipment. This includes well drilling, servicing, production, and pipeline facilities and operations that have the potential for creating a safety hazard or significant environmental impact.

    The elements of these recommended practices should be applied to these facilities, as appropriate. For simple and nearly identical facilities (such as well jackets and single well caissons), certain elements of the safety and environmental management program, as applicable, need be addressed only once, after verifying that site specific deviations have been evaluated.

    When actions are taken in accordance with this recommended practice, such actions should conform to the most current requirements of applicable federal, state, local regulations, or flag State requirements.

    It is recognized that some safety and environmental management systems may have been developed using guidelines of other organizations which may be more appropriate for certain applications (e.g., the International Maritime Organization’s (IMO) International Safety Management (ISM) Code for vessel operations). In assessing these systems against this recommended practice the focus should be on assuring the necessary program elements are addressed, not the format or order of the system documentation.

    1.3.1.2 The operator should establish and maintain a procedure to identify the environmental impacts of its activities, products or services that it can control and over which it can be expected to have an influence, in order to determine those which can be expected to have or can have significant impacts on the environment. These should include “toxics”, “flammables”, and “other material” as described in 1.3.1.3 and 1.3.1.4. Consideration should be given to performing the hazard analysis in accordance with API RP 14J, if applicable.

    1.3.1.3 Toxic substances sometimes handled in OCS operations include hydrogen sulfide (H2S), chlorine (Cl2), and ammonia (NH3). The following are examples of facilities other than oil, gas, and sulphur extraction facilities to which this recommended practice also may be applicable:

    a. Offshore liquefied natural gas (LNG) facilities

    b. Hydrogen sulfide and sulphur recovery facilities.

    c. Chlorine handling and storage facilities.

    d. Ammonia storage and refrigeration facilities.

    1.3.1.4 Due to their thermal, physical, or chemical properties, other materials handled in offshore operations may constitute a safety or environmental hazard if released in an uncontrolled manner. Such substances include steam, hot water, certain chemicals, heat transfer fluids, molten sulphur, and naturally occurring radioactive material (NORM).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/2c5c7283-a918-4b2a-bea6-c75c71a420d1.htm 01-May-04
    API RP 75 3RD ED (R 2013) Recommended Practice for Development of a Safety and Environmental Management Program for Offshore Operations and Facilities; Third Edition; Reaffirmed, April 2013 1.3.1.1 This recommended practice is intended for application

    to offshore oil, gas, and sulphur facilities and associated equipment. This includes well drilling, servicing, production, and pipeline facilities and operations that have the potential for creating a safety hazard or significant environmental impact.

    The elements of these recommended practices should be applied to these facilities, as appropriate. For simple and nearly identical facilities (such as well jackets and single well caissons), certain elements of the safety and environmental management program, as applicable, need be addressed only once, after verifying that site specific deviations have been evaluated.

    When actions are taken in accordance with this recommended practice, such actions should conform to the most current requirements of applicable federal, state, local regulations, or flag State requirements.

    It is recognized that some safety and environmental management systems may have been developed using guidelines of other organizations which may be more appropriate for certain applications (e.g., the International Maritime Organization’s (IMO) International Safety Management (ISM) Code for vessel operations). In assessing these systems against this recommended practice the focus should be on assuring the necessary program elements are addressed, not the format or order of the system documentation.

    1.3.1.2 The operator should establish and maintain a procedure to identify the environmental impacts of its activities, products or services that it can control and over which it can be expected to have an influence, in order to determine those which can be expected to have or can have significant impacts on the environment. These should include “toxics”, “flammables”, and “other material” as described in 1.3.1.3 and 1.3.1.4. Consideration should be given to performing the hazard analysis in accordance with API RP 14J, if applicable.

    1.3.1.3 Toxic substances sometimes handled in OCS operations include hydrogen sulfide (H2S), chlorine (Cl2), and ammonia (NH3). The following are examples of facilities other than oil, gas, and sulphur extraction facilities to which this recommended practice also may be applicable:

    a. Offshore liquefied natural gas (LNG) facilities

    b. Hydrogen sulfide and sulphur recovery facilities.

    c. Chlorine handling and storage facilities.

    d. Ammonia storage and refrigeration facilities.

    1.3.1.4 Due to their thermal, physical, or chemical properties, other materials handled in offshore operations may constitute a safety or environmental hazard if released in an uncontrolled manner. Such substances include steam, hot water, certain chemicals, heat transfer fluids, molten sulphur, and naturally occurring radioactive material (NORM).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/9f6c6a1e-196f-4956-a83f-7ad1aeef4190.htm 01-May-04
    API RP 75 4TH ED (2019) Safety and Environmental Management System for Offshore Operations and Assets; Fourth Edition; December 2019 1 Scope

    This recommended practice provides companies engaged in offshore operations with a framework for the establishment, implementation, and maintenance of a Safety and Environmental Management System (SEMS) to manage and reduce risks associated with safety and the environment to prevent incidents and events.

    This recommended practice applies, in part or whole, to companies engaged in offshore operations, from lease evaluation through decommissioning.

    For the purpose of simplicity and clarity in this recommended practice, the word “safety” or “safely” can refer to the management of safety and environmental risks.

    NOTE Although this recommended practice is written for offshore operations, its principles can be applied to other offshore industries after performing an engineering and management analysis.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/24ccd912-a65b-42d6-b6f1-92e30d8c1949.htm 01-Dec-19
    API RP 77 1ST ED (2018) Risk-based Approach for Managing Hydrocarbon Vapor Exposure during Tank Gauging, Sampling, and Maintenance of Onshore Production Facilities; First Edition http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9a7437d7-c2f0-443a-8805-e7b01b6c553b.htm 01-Jun-18
    API RP 7C-11F 2ND ED (R 1960) API Recommended Practice for Installation, Maintenance, and Operation of Interal-Combustion Engines; Second Edition This recommended practice is under the joint jurisdiction of the API Committee on Standardization of Rotary Drilling Equipment and the API Committee on Standardization of Production Equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8039ca80-06bc-4f4c-b5e2-fe59a6fb1c5f.htm 01-Jan-60
    API RP 7C-11F 3RD ED (1968) API Recommended Practice for Installation, Maintenance, and Operation of Interal-Combustion Engines; Third Edition This recommended practice is under the joint jurisdiction of the API Committee on Standardization of Rotary Drilling Equipment and the API Committee on Standardization of Production Equipment and has been prepared in cooperation with the American Association of Oilwell Drilling Contractors.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/dfe8e8f1-036c-4dc4-9e92-c174c5cc9b96.htm 01-Mar-68
    API RP 7C-11F 4TH ED (R 1988) Recommended Practice for Installation, Maintenance, and Operation of Interal-Combustion Engines; Fourth Edition This recommended practice is under the jurisdiction of the API Committee on Standardization of Production Equipment


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0aaa28a9-ae77-43fe-a0fb-fa82064374c6.htm 01-Apr-81
    API RP 7C-11F 5TH ED (1994) Recommended Practice for Installation, Maintenance, and Operation of Interal-Combustion Engines; Fifth Edition This recommended practice is under the jurisdiction of the API Committee on Standardization of Production Equipment.

    A related specification issued by the Division of Production, American Petroleum Institute, is: "Spec 7B-11C Specification for Internal-Combustion Reciprocating Engines for Oil-Field Service". It covers methods of testing and rating internal-combustion reciprocating engines for application to specific oil-field service.

    This standard shall become effective on the date printed on the cover but may be used voluntarily from the date of distribution.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/47ec6422-896f-4e4f-8abd-f339c977934c.htm 01-Nov-94
    API RP 7G 16TH ED (E1) (A1) (A2) (R 2015) Recommended Practice for Drill Stem Design and Operating Limits; Sixteenth Edition; Effective Date: December 1, 1998; Reaffirmed, May 2015 This recommended practice involves not only the selection of drill string members, but also the consideration of hole angle control, drilling ßuids, weight and rotary speed, and other operational procedures.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/dc8b4d56-6639-4161-b634-34e3d7db96ef.htm 01-Aug-98
    API RP 7G-2 1ST ED (E1) (R 2015) Recommended Practice for Inspection and Classification of Used Drill Stem Elements; First Edition; Reaffirmed, April 2015; ISO 10407-2:2008 This part of ISO 10407 specifies the required inspection for each level of inspection (Tables B.1 through B.15) and procedures for the inspection and testing of used drill stem elements. For the purpose of this part of ISO 10407, drill stem elements include drill pipe body, tool joints, rotary-shouldered connections, drill collar, HWDP and the ends of drill stem elements that make up with them. This part of ISO 10407 has been prepared to address the practices and technology commonly used in inspection. The practices established within this part of ISO 10407 are intended as inspection and/or testing guidance and are not intended to be interpreted to prohibit the agency or owner from using personal judgment, supplementing the inspection with other techniques, extending existing techniques or re-inspecting certain lengths. This part of ISO 10407 specifies the qualification of inspection personnel, a description of inspection methods and apparatus calibration and standardization procedures for various inspection methods. The evaluation of imperfections and the marking of inspected drill stem elements is included. This part of ISO 10407 provides the original equipment manufacturers' requirements regarding the minimum information needed for the inspection of their specialized tools in Annex A.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/347a3d57-f158-450c-85c3-a6b2daf061b7.htm 01-Apr-15
    API RP 7HU1 1ST ED (2009) Safe Use of 2-inch Hammer Unions for Oilfield Applications; First Edition This recommended practice (RP) sets forth procedural recommendations as well as an engineering solution to the mismatching of a female 2-inch Figure 402, a female 2-inch Figure 602, or a female 2-inch Figure 1002 hammer union component (sub) with a male 2-inch Figure 1502 hammer union component (wing nut) as described in 3.2. The procedural recommendations described in this RP should be implemented to reduce further incidents.

    The engineering solution, which prevents the mating of female 2-inch Figure 402, 2-inch Figure 602 and/or 2-inch Figure 1002 subs with the wing nut of the 2-inch Figure 1502 hammer union, applies to the manufacture of new hammer union components and should not be applied in the modification of existing hammer union components due to unknown factors caused by field wear.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fd3a8249-191c-4b34-a7d2-d1448800e888.htm 01-May-09
    API RP 7HU1 1ST ED (E1) (R 2014) Safe Use of 2-inch Hammer Unions for Oilfield Applications; First Edition; Reaffirmed, April 2014 This recommended practice (RP) sets forth procedural recommendations as well as an engineering solution to the mismatching of a female 2-inch Figure 402, a female 2-inch Figure 602, or a female 2-inch Figure 1002 hammer union component (sub) with a male 2-inch Figure 1502 hammer union component (wing nut) as described in 3.2. The procedural recommendations described in this RP should be implemented to reduce further incidents.

    The engineering solution, which prevents the mating of female 2-inch Figure 402, 2-inch Figure 602 and/or 2-inch Figure 1002 subs with the wing nut of the 2-inch Figure 1502 hammer union, applies to the manufacture of new hammer union components and should not be applied in the modification of existing hammer union components due to unknown factors caused by field wear.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/65cbe9d2-ae4a-4f65-b24a-2eddb65d7945.htm 01-May-09
    API RP 7HU1 1ST ED (E1) (R 2020) Safe Use of 2-inch Hammer Unions for Oilfield Applications; First Edition; Reaffirmed, March 2020 This recommended practice (RP) sets forth procedural recommendations as well as an engineering solution to the mismatching of a female 2-inch Figure 402, a female 2-inch Figure 602, or a female 2-inch Figure 1002 hammer union component (sub) with a male 2-inch Figure 1502 hammer union component (wing nut) as described in 3.2. The procedural recommendations described in this RP should be implemented to reduce further incidents.

    The engineering solution, which prevents the mating of female 2-inch Figure 402, 2-inch Figure 602 and/or 2-inch Figure 1002 subs with the wing nut of the 2-inch Figure 1502 hammer union, applies to the manufacture of new hammer union components and should not be applied in the modification of existing hammer union components due to unknown factors caused by field wear


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/15bd778c-623b-41cd-b2f7-4c4448ef05e2.htm 01-May-09
    API RP 7L 1ST ED (A1) (A2) (R 2012) Procedures for Inspection, Maintenance, Repair, and Remanufacture of Drilling Equipment; First Edition; Effective Date: April 1, 1996; Reaffirmed, August 2012 1.1 OBJECTIVE

    The objective of this publication is to provide owners and users of equipment listed below guidelines for inspection, maintenance, repair, and remanufacture procedures that may be utilized to maintain serviceability of the covered equipment.

    This recommended practice covers the following drilling equipment:

    a. Rotary tables.

    b. Rotary bushings.

    c. Rotary slips.

    d. Rotary hoses.

    e. Slush pump components.

    f. Drawworks components.

    g. Spiders not capable of use as elevators.

    h. Manual tongs.

    i. Safety clamps not used as a hoisting device.

    1.2 PROCEDURE DEVELOPMENT

    The owner or user, together with the manufacturer should jointly develop and update inspection, maintenance, repair, and remanufacture procedures consistent with equipment application, loading, work environment, usage, and other operational conditions. These factors may change from time to time as a result of new technology, equipment history, product improvements, new maintenance techniques, and change in service conditions.

    1.3 PERSONNEL QUALIFICATIONS

    Inspection, maintenance, and repair procedures should be carried out by personnel qualified by professional trade and verified by widely accepted or recognized standards covering the specific skills or knowledge required.

    1.4 DOCUMENTATION

    1.4.1 Records

    The equipment owner or user should maintain a recordkeeping system that contains pertinent information regarding equipment. Records may include the following:

    a. Information provided by the manufacturer.

    b. Inspection records.

    c. Maintenance records.

    d. Repair records.

    e. Remanufacture records.

    1.4.2 Identification

    Unit serial number or identification marking provided by the manufacturer should be maintained on the equipment and recorded in the equipment record. Identification marking should be provided by the owner or user for unidentified equipment that required the maintenance of records.

    1.4.3 History

    Changes in equipment status, which could affect equipment serviceability or maintenance, should be recorded in the equipment record.

    1.4.4 Record Identification

    Entries in the equipment record should include the date and the name of the responsible person(s) involved in the inspection, maintenance, repair, or remanufacture.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/f71902f4-0c49-4dc1-9e1d-fba2f3302df6.htm 01-Aug-12
    API RP 80 1ST ED (R 2013) Guidance for the Definition of Onshore Gas Gathering Lines; First Edition; Reaffirmed, January 2013 This industry standard provides a functional description of onshore gas gathering pipelines for the sole purpose of providing users with a practical guide for determining the application of the definition of gas gathering in the federal Gas Pipeline Safety Standards, 49 CFR Part 192, and state programs implementing these standards.

    The definition of “gas gathering” reflects the varied nature of the gas industry throughout the country. Because of the regional and operational diversity within the gas industry, additional guidance—either within the regulation or through incorporation of a recognized industry standard—is necessary to ensure appropriate and consistent application of the gas gathering line definition. This Recommended Practice was developed as such a standard through the joint efforts of the regulated community.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c6998885-ecb5-4405-9940-c1a1d5c4fcac.htm 01-Apr-00
    API RP 86 1ST ED (2005) API Recommended Practice for Measurement of Multiphase Flow; First Edition This API Recommended Practice arose from a series of meetings that were held during 2003 among measurement experts from several producers who were active offshore in the Gulf of Mexico. This group, the Upstream Allocation Task Group, set out to address the general shortage of standards and recommended practices governing the measurement and allocation of flow in the upstream domain.

    The group that developed this Recommended Practice (RP) was called the Well Rate Determination Subgroup, with the charter to make recommendations regarding measurement of flow rates from individual wells. However, as their work unfolded, the charge was slightly broadened to cover the more general subject of multiphase flow measurement, whether that flow was from a single well or the combined flow of two or more wells.

    1.1 USE WITH OTHER RECOMMENDED PRACTICES

    It is intended that this RP be used in conjunction with other similar documents to guide the user toward good measurement practice in upstream hydrocarbon production applications. The term upstream refers to those measurement points prior to, but not including, the custody transfer point.

    Specifically this document will address in depth the question of how the user measures (multiphase) flow rates of oil, gas, water, and any other fluids that are present in the effluent stream of a single well. This requires the definition not only of the methodology which is to be employed, but also the provision of evidence that this methodology will produce a quality measurement in the intended environment. Most often, this evidence will take the form of a statement of the uncertainty of the measurement, emphasizing how the uncertainty statement was derived.

    This RP will prove especially important when used in conjunction with other similar documents, such as those that address how commingled fluids should be allocated to individual producers. For example API RP 85 Use of Subsea Wet-Gas Flowmeters in Allocation Measurement Systems [Ref. 2] describes a methodology for allocation based on relative uncertainty, the identification of which is discussed in detail in section 8.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/cf4aad0a-afb6-4f4c-8f53-eb22aeedcab8.htm 01-Sep-05
    API RP 90 1ST ED (2006) Annular Casing Pressure Management for Offshore Wells; First Edition This Recommended Practice is intended to serve as a guide for managing annular casing pressure in offshore wells. Although the prevention of annular casing pressure is very important, it is beyond the scope of this document. Prevention of annular casing pressure is planned to be addressed in API RP 65, Part 2. The remediation of wells because of sustained casing pressure is also beyond the scope of this document and is planned to be included in API RP 65, Part 3. This guide is meant to be used for offshore wells that exhibit annular casing pressure, including thermal casing pressure, sustained casing pressure (SCP) and operator-imposed pressure.

    This Recommended Practice covers monitoring, diagnostic testing, the establishment of a maximum allowable wellhead operating pressure (MAWOP) and documentation of annular casing pressure for the various types of wells that occur offshore. Included also is a discussion of risk assessment methodologies that can be used for the evaluation of individual well situations where the annular casing pressure is not within the MAWOP guidelines.

    This Recommended Practice recognizes that annular casing pressure results in various levels of risk to the safety of personnel, property and the environment. The level of risk presented by annular casing pressure depends on many factors, including the design of the well and the source of the annular casing pressure. This Recommended Practice provides guidelines in which a broad range of casing annuli that exhibit annular pressure can be managed in a routine fashion while maintaining an acceptable level of risk. Annular pressures that do not conform to the guidelines in this Recommended Practice may still have an acceptable level of risk, but they need to be evaluated on a case-by-case basis.

    This Recommended Practices establishes an acceptable level of risk for annular casing pressure using three parameters. First, annuli that exhibit annular casing pressure of 100 psig or less present little risk and should be monitored. Second, annular casing pressure that is greater than 100 psig and that has been diagnosed as sustained casing pressure (SCP) must bleed to zero psig. Third, a Maximum Allowable Wellhead Operating Pressure (MAWOP) is established for each non-structural casing annulus that exhibits annular casing pressure, including thermal casing pressure, sustained casing pressure or operator-imposed pressure. If the annular casing pressure does not meet the criteria established in this Recommended Practice, this does not mean that the risk presented by the annular pressure is unacceptable. Rather, it indicates that the annular casing pressure needs to be managed on a case-by-case basis that goes beyond the scope of this Recommended Practice. The case-by-case management of annular casing pressure may include the use of risk assessment techniques. Techniques that may be used for case-by-case risk assessment are discussed in Section 10 of this Recommended Practice. In some cases, the annular casing pressure may need to be reduced or eliminated by well work. In other cases, the risk may be mitigated by other methods. Procedures for eliminating annular casing pressure or mitigating the risk are beyond the scope of this Recommended Practice.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/51a1c051-eccd-4508-bb3a-9da610481b4e.htm 01-Aug-06
    API RP 90 1ST ED (R 2012) Annular Casing Pressure Management for Offshore Wells; First Edition; Reaffirmed, January 2012 This Recommended Practice is intended to serve as a guide for managing annular casing pressure in offshore wells. Although the prevention of annular casing pressure is very important, it is beyond the scope of this document. Prevention of annular casing pressure is planned to be addressed in API RP 65, Part 2. The remediation of wells because of sustained casing pressure is also beyond the scope of this document and is planned to be included in API RP 65, Part 3. This guide is meant to be used for offshore wells that exhibit annular casing pressure, including thermal casing pressure, sustained casing pressure (SCP) and operator-imposed pressure.

    This Recommended Practice covers monitoring, diagnostic testing, the establishment of a maximum allowable wellhead operating pressure (MAWOP) and documentation of annular casing pressure for the various types of wells that occur offshore. Included also is a discussion of risk assessment methodologies that can be used for the evaluation of individual well situations where the annular casing pressure is not within the MAWOP guidelines.

    This Recommended Practice recognizes that annular casing pressure results in various levels of risk to the safety of personnel, property and the environment. The level of risk presented by annular casing pressure depends on many factors, including the design of the well and the source of the annular casing pressure. This Recommended Practice provides guidelines in which a broad range of casing annuli that exhibit annular pressure can be managed in a routine fashion while maintaining an acceptable level of risk. Annular pressures that do not conform to the guidelines in this Recommended Practice may still have an acceptable level of risk, but they need to be evaluated on a case-by-case basis.

    This Recommended Practices establishes an acceptable level of risk for annular casing pressure using three parameters. First, annuli that exhibit annular casing pressure of 100 psig or less present little risk and should be monitored. Second, annular casing pressure that is greater than 100 psig and that has been diagnosed as sustained casing pressure (SCP) must bleed to zero psig. Third, a Maximum Allowable Wellhead Operating Pressure (MAWOP) is established for each non-structural casing annulus that exhibits annular casing pressure, including thermal casing pressure, sustained casing pressure or operator-imposed pressure. If the annular casing pressure does not meet the criteria established in this Recommended Practice, this does not mean that the risk presented by the annular pressure is unacceptable. Rather, it indicates that the annular casing pressure needs to be managed on a case-by-case basis that goes beyond the scope of this Recommended Practice. The case-by-case management of annular casing pressure may include the use of risk assessment techniques. Techniques that may be used for case-by-case risk assessment are discussed in Section 10 of this Recommended Practice. In some cases, the annular casing pressure may need to be reduced or eliminated by well work. In other cases, the risk may be mitigated by other methods. Procedures for eliminating annular casing pressure or mitigating the risk are beyond the scope of this Recommended Practice.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9898c4cb-7091-4680-a17a-6f120402b2e2.htm 01-Aug-06
    API RP 90-2 1ST ED (2016) Annular Casing Pressure Management for Onshore Wells; First Edition 1.1 General

    This document is intended to serve as a guide to monitor and manage annular casing pressure (ACP) in onshore wells, including production, injection, observation/monitoring, and storage wells. This document applies to wells that exhibit thermally induced, operator-imposed, or sustained ACP. It includes criteria for establishing diagnostic thresholds (DTs), monitoring, diagnostic testing, and documentation of ACP for onshore wells. Also included is a discussion of risk management considerations that can be used for the evaluation of individual well situations where the annular casing pressure falls outside the established diagnostic thresholds.

    This document recognizes that an ACP outside of the established DTs can result in a risk to well integrity. The level of risk presented by ACP depends on many factors, including the design of the well, the performance of barrier systems within the well, the source of the annular casing pressure, and whether there is an indication of annular flow exists. This document provides guidelines in which a broad range of casing annuli that exhibit annular casing pressure can be managed while maintaining well integrity.

    1.2 Conditions of Applicability

    This document applies to annular casing pressure management in onshore wells during normal operation. In this context, normal operation is considered the operational phase during the life of a well that begins at the end of the well construction process and extends through the initiation of well abandonment operations, excluding any periods of well intervention or workover activities.

    The design and construction of wellbores for the prevention of unintended ACP and the management of ACP during drilling, completion, well intervention and workover, and abandonment operations are beyond the scope of this document. The isolation of potential flow zones during well construction (zones that can be the source of sustained annular casing pressure) is addressed in API 65-2. In some cases, the annular casing pressure can be reduced or remediated. The remediation of sustained casing pressure (SCP) is also beyond the scope of this document.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/04336e2e-c828-45f7-a2e2-df0051e17ebf.htm 01-Apr-16
    API RP 92M 1ST ED (2017) Managed Pressure Drilling Operations with Surface Back-pressure; First Edition This document provides information for planning, installation, testing and operation of wells drilled with surface backpressure managed pressure drilling (MPD). This document applies only to drilling rigs with surface blowout preventers (BOPs).

    This document considers situations where the total drilling operation is performed balanced or overbalanced, including both hydrostatically overbalanced (no supplemental surface pressure needed to control inflow) and hydrostatically underbalanced (supplemental surface pressure needed to control inflow) systems. For underbalanced operations, refer to API 92U.

    This document does not cover MPD operations with subsea BOP stacks.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/a8dfdc64-87c3-4ef3-8e3e-914729ea3754.htm 01-Sep-17
    API RP 92M 1ST ED (E1) Managed Pressure Drilling Operations with Surface Back-pressure; First Edition http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e335bd87-f81a-4818-a4d0-179c02b02855.htm 01-Sep-17
    API RP 92P 1ST ED (2019) Managed Pressure Drilling Operations — Pressurized Mud Cap Drilling with a Subsea Blowout Preventer; First Edition This document addresses recommended practices for pressurized mud cap drilling (PMCD) from a floating rig with a subsea BOP stack. When massive lost circulation conditions are encountered, PMCD can be implemented to allow well construction operations to continue:

    Although this document only addresses PMCD, most of the equipment described may also be used for the surface back-pressure (SBP) method of managed pressure drilling. However, much of the equipment used for SBP is not required for PMCD, and will not be covered here.

    The following methods, described briefly, are also used during lost circulation conditions; however, they are outside the scope of this document:

    a)blind drilling (see 4.3.2);

    b)continuous annular injection drilling (see 4.3.3);

    c)floating mud cap drilling (see 4.3.4).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3ef630d1-a136-4bb3-9287-d59f860c80c7.htm 01-Jun-19
    API RP 92S 1ST ED (2018) Managed Pressure Drilling Operations—Surface Back-pressure with a Subsea Blowout Preventer; First Edition 1.1 General

    This document provides information for planning, installation, testing, and operation of wells drilled with surface back-pressure (SBP) managed pressure drilling (MPD). This document applies only to drilling rigs with subsea blowout preventers (BOPs).

    This document addresses situations where the total drilling operation is performed balanced or overbalanced, including both hydrostatically overbalanced (no supplemental surface pressure needed to control inflow) and hydrostatically underbalanced (supplemental surface pressure needed to control inflow) systems. For underbalanced operations refer to API 92U.

    1.2 Installation and Use of Blowout Preventers

    Installation, testing, and use of BOPs and associated secondary well control equipment are similar to conventional drilling operations and are not included in this publication. This equipment should only be used during routine MPD operations (e.g. seal element changeout) if an adequate risk assessment has been performed. Refer to API 53 for information regarding installation and testing of BOPs in a conventional drilling operation.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c7681adb-8b54-478f-9b3d-e35d560ed5e1.htm 01-Sep-18
    API RP 92U 1ST ED (2008) Underbalanced Drilling Operations; First Edition The purpose of these recommended practices is to provide information that can serve as a guide for planning, installation, operation and testing of underbalanced drilling equipment systems on land and offshore drilling rigs [barge, platform, bottom-supported, and floating with surface blowout preventers (BOP) installed] thereby ensuring consideration of personnel safety, public safety, integrity of the underbalanced drilling (UBD) equipment, and preservation of the environment for onshore and offshore UBD operations (including tripping of drill string).

    The UBD system is composed of all equipment required to safely allow drilling ahead in geological formations with pressure at surface and under varying rig and well conditions. These systems include: the rig circulating equipment, the drill string, drill string non return valves (NRV), surface BOP, control devices (rotating or non-rotating) independent of the BOP, choke and kill lines, UBD flowlines, choke manifolds, hydraulic control systems, UBD separators, flare lines, flare stacks and flare pits and other auxiliary equipment. The primary functions of these systems are to contain well fluids and pressures within a design envelope in a closed flow control system, provide means to add fluid to the wellbore, and allow controlled volumes to be withdrawn from the wellbore.

    1.1.1 Managed pressure drilling (Category A) and mud cap drilling (Category C) techniques as defined in the IADC Well Classification System for Underbalanced Operations and Managed Pressure Drilling are not included in this publication. The phrase managed pressure drilling or the acronym MPD is only used in this document in the context of the IADC Well Classification System.

    1.1.2 Sub-sea BOP stacks and marine risers are not dealt with in this document.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/b937a385-0651-44b6-aca6-12c77c978203.htm 01-Nov-08
    API RP 92U 1ST ED (R 2013) Underbalanced Drilling Operations; First Edition; Reaffirmed, April 2013 The purpose of these recommended practices is to provide information that can serve as a guide for planning, installation, operation and testing of underbalanced drilling equipment systems on land and offshore drilling rigs [barge, platform, bottom-supported, and floating with surface blowout preventers (BOP) installed] thereby ensuring consideration of personnel safety, public safety, integrity of the underbalanced drilling (UBD) equipment, and preservation of the environment for onshore and offshore UBD operations (including tripping of drill string).

    The UBD system is composed of all equipment required to safely allow drilling ahead in geological formations with pressure at surface and under varying rig and well conditions. These systems include: the rig circulating equipment, the drill string, drill string non return valves (NRV), surface BOP, control devices (rotating or non-rotating) independent of the BOP, choke and kill lines, UBD flowlines, choke manifolds, hydraulic control systems, UBD separators, flare lines, flare stacks and flare pits and other auxiliary equipment. The primary functions of these systems are to contain well fluids and pressures within a design envelope in a closed flow control system, provide means to add fluid to the wellbore, and allow controlled volumes to be withdrawn from the wellbore.

    1.1.1 Managed pressure drilling (Category A) and mud cap drilling (Category C) techniques as defined in the IADC Well Classification System for Underbalanced Operations and Managed Pressure Drilling are not included in this publication. The phrase managed pressure drilling or the acronym MPD is only used in this document in the context of the IADC Well Classification System.

    1.1.2 Sub-sea BOP stacks and marine risers are not dealt with in this document.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/c3c5e0d7-3b7a-4819-aa1f-1daf3e4ea0f6.htm 01-Nov-08
    API RP 95F 1ST ED (2006) Interim Guidance for Gulf of Mexico MODU Mooring Practice—2006 Hurricane Season; First Edition This document provides guidance and processes and, when combined with an understanding of the environment at a particular location, the characteristics of the unit being utilized, and other factors, may be used to enhance operational integrity in the survival condition. This guidance was developed through a cooperative arrangement with the American Petroleum Institute’s Subcommittee on Offshore Structures RP 2SK Task Group, the International Association of Drilling Contractors (IADC) Offshore Operations Division, and the Joint Industry Project entitiled “US Gulf of Mexico Mooring Strength Reliabilty” (MODU JIP). The information presented herein is premised on the existence of a MODU evacuation plan, the intent of which is to assure timely and safe evacuation of all MODU personnel in anticipation of hurricane conditions.

    This guidance is of an interim nature and is supplemental to the existing API RP 2SK, “Design and Analysis of Stationkeeping Systems for Floating Structures,” 3rd Edition (2005). This guidance also addresses documentation expectations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/ba8dd46f-7dbd-4092-a210-cbd9e4077d08.htm 01-May-06
    API RP 95J 1ST ED (R 2008) Gulf of Mexico Jackup Operations for Hurricane Season; First Edition; Reaffirmed, February 2008 The purpose of this recommended practice (RP) is to present an approach to siting Jackup Mobile Offshore Drilling Units (MODUs) and to recommend certain operational procedures to enhance jackup survivability and stationkeeping during hurricane season in the Gulf of Mexico during drilling, workover, and while stacked (idled) at a non-sheltered location. This document provides guidance and processes and, when combined with an understanding of the environment at a particular location, the characteristics of the unit being utilized, and other factors, may be used to enhance operational integrity. This RP was developed through a cooperative arrangement with the International Association of Drilling Contractors’ (IADC) Jackup Rig Committee. The information presented herein is premised on the existence of an evacuation plan, the intent of which is to assure timely evacuation of all rig personnel in anticipation of certain climatic conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ecc63de7-3842-4445-83c0-de110600455d.htm 01-Jun-06
    API RP 95J 1ST ED (R 2013) Gulf of Mexico Jackup Operations for Hurricane Season; First Edition; Reaffirmed, April 2013 The purpose of this recommended practice (RP) is to present an approach to siting Jackup Mobile Offshore Drilling Units (MODUs) and to recommend certain operational procedures to enhance jackup survivability and stationkeeping during hurricane season in the Gulf of Mexico during drilling, workover, and while stacked (idled) at a non-sheltered location. This document provides guidance and processes and, when combined with an understanding of the environment at a particular location, the characteristics of the unit being utilized, and other factors, may be used to enhance operational integrity. This RP was developed through a cooperative arrangement with the International Association of Drilling Contractors’ (IADC) Jackup Rig Committee. The information presented herein is premised on the existence of an evacuation plan, the intent of which is to assure timely evacuation of all rig personnel in anticipation of certain climatic conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d00e2275-7198-41ef-956b-489b3aac3882.htm 01-Jun-06
    API RP 96 1ST ED (2013) Deepwater Well Design and Construction; First Edition The complexity of deepwater (DW) operations requires a thorough understanding

    of well design criteria and associated equipment. This recommended practice (RP) provides engineers a reference for DW well design as well as drilling and completion operations. This RP will also be useful to support internal reviews, internal approvals, contractor engagements, and regulatory approvals.

    The scope of this RP is to discuss DW drilling and completion activities performed on wells that are constructed using subsea blowout preventers (BOPs) with a subsea wellhead. This document addresses the following.

    — Identifies the appropriate barrier and load case considerations to maintain well control during DW well operations (drilling, suspension, completion, production, and abandonment).

    — Supplements barrier documentation in API 65-2 with a more detailed description of barriers and discussion of the philosophy, number, type, testing, and management required to maintain well control. This document also supplements the barrier documentation in API 90 in regard to annular pressure buildup (APB). Abandonment barrier requirements are described for use when designing the well.

    — Discusses load assumptions, resistance assumptions, and methodologies commonly used to achieve well designs with high reliability. The load case discussion includes less obvious events that can arise when unexpected circumstances are combined.

    — Describes the risk assessment and mitigation practices commonly implemented during DW casing and equipment installation operations.

    The purpose of this document is to enhance safety and minimize the likelihood of loss of well control or damage to the environment. These practices are generally intended to apply to subsea wells drilled with subsea BOPs in any water depth. Some of the descriptions of rig hardware and operations, such as remotely operated vehicles (ROVs), are less relevant in shallower water depths [e.g. less than 500 ft (152 m)]. In these shallower water depths the operator may substitute alternative hardware or operations that maintain safety and system reliability.

    The following aspects of DW well design and construction are outside the scope of this document.

    — Detailed casing design load case definitions (does not include specific casing designs or design factors). Individual companies combine differing severities of loads and resistances or differing calculation methods to achieve designs with similar high levels of reliability.

    — Wells drilled and/or completed with a surface BOP and high pressure riser from a floating production system; however, considerations for wells predrilled with floating rigs to be completed to a floating production system are included.

    — Well control procedures (refer to API 59 for well control information).

    — Managed pressure drilling operations (including dual gradient drilling).

    — Production operations and fluids handling downstream of the tree (subsea facilities/subsea architecture, and surface facilities/offloading hydrocarbons).

    — Intervention operations.

    — Quality assurance (QA) programs.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/7a29c3d8-a342-496f-b7b6-50ed2bdb61e7.htm 01-Mar-13
    API RP 98 1ST ED (2013) Personal Protective Equipment Selection for Oil Spill Responders; First Edition This recommended practice (RP) provides general information and guidance for the development of oil spill responder personal protective equipment (PPE) control measures. Although an extensive amount of information has been developed on the topic of PPE for emergency responders, this document focuses on the PPE selection process as well as its technical evaluation based on the hazards present.

    This RP is intended for any company, organization, or agency that oversees or responds to oil spills. It is not a comprehensive “how-to” guide to selecting PPE for every type of situation that may be encountered; rather, it is a guidance document that discusses how proper PPE selection may be a useful control measure for responders when engineering and administrative controls may not be feasible or effective in reducing exposure to acceptable levels.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5cfa9327-0f67-4037-acf0-ffec718760f6.htm 01-Aug-13
    API RP 99 1ST ED (2014) Flash Fire Risk Assessment for the Upstream Oil and Gas Industry; First Edition 1.1 General

    This recommended practice (RP) provides guidance for the upstream oil and gas industry on hazard identification and risk assessment exercises to assess and mitigate the risk of human injury caused by exposure to a flash fire.

    The scope of this document is limited to personnel exposed to the risk of hydrocarbon based flash fires in the upstream Exploration and Production sector of the oil and gas industry. In general, this group includes oil and gas production, drilling, well bore (well servicing) operations, and gas processing prior to interstate pipeline transportation.

    1.2 Conditions of Applicability

    This RP focuses on flash fires that result from the unexpected ignition of hydrocarbon vapors. Emergency preparedness (e.g. firefighting, hazmat response) for exposure to fire event greater than a flash fire is excluded from this RP and is addressed by NFPA and other standards organizations.

    Arc flash, as discussed in NFPA 70E and its other related standards, are outside the scope of this document.

    Maintenance, care, and limitation of various fire resistant clothing (FRC) materials are outside the scope of this document. These items are addressed by the manufacturer and clothing-related standards.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d960c7c2-ae0b-4403-9b7b-080708743955.htm 01-Apr-14
    API RP 9B 14TH ED (2015) Application, Care, and Use of Wire Rope for Oil Field Service; Fourteenth Edition This recommended practice (RP) covers typical wire rope applications for the oil and gas industry.

    Typical practices in the application of wire rope to oil field service are indicated in Table 1, which shows the sizes and constructions commonly used. Because of the variety of equipment designs, the selection of constructions other than those shown is justifiable.

    In oilfield service, wire rope is often referred to as wire line or cable. For the purpose of clarity, these various expressions are incorporated in this recommended practice.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/1e93d46e-8a46-4d5a-94f5-d9876e333c9f.htm 01-Oct-15
    API RP T-1 4TH ED (R 2013) Orientation Programs for Personnel Going Offshore for the First Time; Fourth Edition; Reaffirmed, January 2013 This Recommended Practice is intended to serve as a guide to develop orientation standards and programs applicable to all employees and visitors. The orientation programs should ensure that all new personnel know what is expected of them during the first trip offshore, as well as what they may expect to encounter during this trip. Employers have the option, of course, to institute broader procedures commensurate with their own policies and standards.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/993ae5f4-0c1d-4e43-a313-8249c3e4e4a4.htm 01-Jan-13
    API RP T-2 2ND ED (R 2013) Recommended Practice for Qualification Programs for Offshore Production Personnel Who Work with Safety Devices; Second Edition; Reaffirmed, January 2013 This Recommended Practice provides guidelines for the qualification of personnel engaged in installing, inspecting, testing, and routinely maintaining surface and subsurface devices that are used to insure safety and to prevent pollution during the production of oil and gas on offshore platforms. These guidelines provide expected candidate performance levels, instructional content and recommendations for testing. A certificate is issued to the candidate upon successful completion of the testing phase.

    The value of work experience is recognized by dividing the guidelines into instructional and testing phases. Any candidate who has the experience prerequisites may complete only the testing phase. If a candidate demonstrates proficiency in all classes of safety devices, a certificate is issued identical to those issued to candidates who first take the instructional phase and then pass the testing phase.

    This Recommended Practice (RP) complements API RP 14B, API RP 14C and API RP 14H as well as other API Specifications.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/24504f79-7cf6-4ced-b466-759a8f151d66.htm 01-Jan-13
    API RP T-4 2ND ED (R 2010) Training of Offshore Personnel in Nonoperating Emergencies; Second Edition; Reaffirmed, September 2010 This Recommended Practice is applicable to personnel who normally work offshore. It presents recommendations for training these personnel in handling nonoperating emergencies, such as fires, transportation emergencies, platform abandonment procedures, use of survival craft, and water survival guidelines.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/2a513647-3cfe-46df-8194-01a5e234ad0f.htm 01-Sep-10
    API RP T-6 1ST ED (R 2013) Recommended Practice for Training and Qualification of Personnel in Well Control Equipment and Techniques for Wireline Operations on Offshore Locations; First Edition; Reaffirmed, January 2013 This Recommended Practice (RP) provides criteria for the qualification of wireline personnel in well control equipment operations and techniques. Although it does include recommendations for training wireline personnel on general rig well control equipment and theory, it should be noted that the main focus for training should be those operations using a lubricator as the primary well control mechanism. Wireline personnel classifications to which this RP is applicable are the Helper/ Assistant and Operator/Supervisor. This RP is intended for the development of training courses with well-defined curricula and includes recommendations for testing to assure that a candidate is qualified when he/she completes a course.

    The employer should maintain a record of the training which each employee receives in accordance with this RP. Each employee should be furnished documentation of the successful completion of each level of training.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/70ba0080-ddf5-45f7-af21-1122ea696cf8.htm 01-Jan-13
    API RP T-7 2ND ED (R 2013) Training of Personnel in Rescue of Persons in Water; Second Edition; Reaffirmed, January 2013 This Recommended Practice applies to personnel who work offshore and represents an industry guide for training personnel in techniques for rescuing persons from the water and from survival devices in the water. It broadly identifies rescue devices, describes their operations, and presents recommendations for training personnel in their use as either a rescuer or a person being rescued. These training recommendations are designed to develop personnel rescue proficiency while minimizing an individual's exposure to injury or loss of life.

    The training may be either hands-on or classroom based. Some suggested approaches are included. The Recommended Practice encourages the employer, when deciding the conditions under which training and drills are to be carried out, to fully consider all safety aspects of the training. Training should be as broad as is practical. It should emphasize those devices likely to be available to the employee at his or her assigned location.

    These guidelines are general and may or may not be sufficient for all circumstances or operations. The employer should not limit or reduce the company's present program as a result of the publication of these guidelines.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3314de9b-35a0-4c88-bed1-8f842a5ae0a2.htm 01-Jan-13
    API RP T-8 1ST ED (2019) Fundamental Safety Training for Offshore Personnel; First Edition This recommended practice provides guidance on the components of an effective training system related to offshore health, safety, and environment (HSE). A common safety training matrix is provided that outlines the fundamental recommended HSE training for offshore personnel. This matrix can be used in conjunction with other applicable recommended training and company-specific requirements.

    NOTE This recommended practice is focused on the components of an effective training system, which can be used to manage any type of training. Annex A lists the fundamental safety training and frequencies recommended to work offshore. The need for additional specific safety or technical training is outside the scope of this document.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/7142cb94-4ecb-4b06-9e92-306b318fe52f.htm 01-Jan-19
    API SDS PETROLEUM INDUSTRY PRACTICES (2008) Safety Data Sheets: Petroleum Industry Practices; November 2008 In October 2008, the American Petroleum Institute (API) conducted a review of

    member company practices for development and delivery of SDSs and hazard communication to shippers and seafarers. The information presented in this document applies to practices for MARPOL Annex I type cargoes and marine fuel oils (e.g., crude oils; fuel and residual oils; unfinished distillates, hydraulic oils, and lubricating oils; gas oils; kerosenes; naphthas and condensates; gasoline blending stocks; gasoline and spirits; and asphalt solutions).

    API also reviewed relevant hazard communication regulations and standards, as well as example API member company SDSs. The goal of this document is to summarize the information API collected on petroleum industry practices for SDSs and hazard communication relevant to shippers and seafarers.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/de840886-9a5e-4449-b5ad-43f62b6bbe2a.htm 01-Nov-08
    API SPEC 10F 4TH ED (2018) Cementing Float Equipment Testing; Fourth Edition This specification provides testing and marking requirements for cementing float equipment to be used in oil and natural gas well construction.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8226d5f3-6e3c-48ab-af61-14e3838ef8f5.htm 01-Jul-18
    API SPEC 11AX 13TH ED (2015) Specification for Subsurface Sucker Rod Pump Assemblies, Components, and Fittings; Thirteenth Edition; Effective Date: November 4, 2015 This specification provides the requirements and guidelines for the design of subsurface sucker rod pumps and their components as defined herein for use in the sucker rod lift method for the petroleum and natural gas industry.

    The specification covers subsurface sucker rod pump assemblies (including insert and tubing), components and fittings, in commonly used bore sizes for the sucker rod lift method. Sufficient dimensional and material requirements are provided to assure interchangeability and standardization of all component parts.

    Many components and fittings are prescriptively specified in this standard and thus do not require a design package. However, some components require design packages. These components are listed in the following tables: C.10 through C.18, C.22, C.23, C.28, C.30, C.32, C.33, C.37, C.38, C.39, C.40, C.41, C.44, C.49, C.53, C.54, C.55, C.59.

    The specification does not cover specialty subsurface sucker rod pump accessories or special design components. Also, installation, operation, and maintenance of these products are not included in this specification, however recommendations can be found in API 11AR.

    The formulation and publication of API specifications and the API monogram program are not intended in any way to inhibit the purchase of products from companies not licensed to use the API monogram.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/b0fa8c0b-da5e-4ed1-a7d3-e0bb5f9e5771.htm 01-May-15
    API SPEC 11AX 13TH ED (A1) Specification for Subsurface Sucker Rod Pump Assemblies, Components, and Fittings; Thirteenth Edition; Effective Date: November 4, 2015 1 Scope

    This specification provides the requirements and guidelines for the design of subsurface sucker rod pumps and their components as defined herein for use in the sucker rod lift method for the petroleum and natural gas industry.

    The specification covers subsurface sucker rod pump assemblies (including insert and tubing), components and fittings, in commonly used bore sizes for the sucker rod lift method. Sufficient dimensional and material requirements are provided to assure interchangeability and standardization of all component parts.

    Many components and fittings are prescriptively specified in this standard and thus do not require a design package. However, some components require design packages. These components are listed in the following tables: C.10 through C.18, C.22, C.23, C.28, C.30, C.32, C.33, C.37, C.38, C.39, C.40, C.41, C.44, C.49, C.53, C.54, C.55, C.59.

    The specification does not cover specialty subsurface sucker rod pump accessories or special design components. Also, installation, operation, and maintenance of these products are not included in this specification, however recommendations can be found in API 11AR.

    The formulation and publication of API specifications and the API monogram program are not intended in any way to inhibit the purchase of products from companies not licensed to use the API monogram.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3e3d8c1f-a0f9-4e63-a943-80dbfdaefef9.htm 01-May-15
    API SPEC 11B 27TH ED (E1) (E2) Specification for Sucker Rods, Polished Rods and Liners, Couplings, Sinker Bars, Polished Rod Clamps, Stuffing; Twenty-Seventh Edition; Effective Date: November 1, 2010 This specification provides the requirements and guidelines for the design of steel sucker rods and pony rods, polished rods, polished rod liners, couplings and sub-couplings, fiber reinforced plastic (FRP) sucker rods, sinker bars, polished rod clamps, stuffing boxes, and pumping tees as defined herein for use in the sucker rod lift method for the petroleum and natural gas industry. Annex A through Annex H provide the requirements for specific products. Annex I includes the requirements for thread gauges, Annex J illustrates the components of a sucker rod lift system, and Annex K shows examples of sucker rod discontinuities.

    This specification does not cover sucker rod guides, sucker rod rotators, shear tools, on-off tools, stabilizer bars, sealing elements used in stuffing boxes, or interface connections for stuffing boxes and pumping tees. Also, installation, operation and maintenance of these products are not included in this specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/87a7a7a1-639a-4cb4-a577-5dabcc7701c5.htm 01-Feb-11
    API SPEC 11E 19TH ED (E1) Specification for Pumping Units; Nineteenth Edition; Effective Date: May 1, 2014 This specification provides the requirements and guidelines for the design and rating of beam pumping units for use in the petroleum and natural gas industry. Included are all components between the carrier bar and the speed reducer input shaft.

    This includes the following:

    a) beam pump structures,

    b) pumping unit gear reducer, and

    c) pumping unit chain reducer.

    Only loads imposed on the structure and/or gear reducer by the polished rod load are considered in this specification.

    Also included are the requirements for the design and rating of enclosed speed reducers wherein the involute gear tooth designs include helical and herringbone gearing. The rating methods and influences identified in this specification are limited to single and multiple stage designs applied to beam pumping units in which the pitch-line velocity of any stage does not exceed 5000 ft/min and the speed of any shaft does not exceed 3600 rpm.

    This standard does not cover chemical properties of materials, installation and maintenance of the equipment, beam type counterbalance units, prime movers and power transmission devices outside the gear reducer, or control systems.

    See Annex A for product is supplied bearing the API Monogram and manufactured at a facility licensed by API.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/2639303d-668c-4405-87f6-2022ab5ea95a.htm 01-Nov-13
    API SPEC 11E 19TH ED (E1) (A1) Specification for Pumping Units; Nineteenth Edition; Effective Date: May 1, 2014 This specification provides the requirements and guidelines for the design and rating of beam pumping units for use in the petroleum and natural gas industry. Included are all components between the carrier bar and the speed reducer input shaft.

    This includes the following:

    a) beam pump structures,

    b) pumping unit gear reducer, and

    c) pumping unit chain reducer.

    Only loads imposed on the structure and/or gear reducer by the polished rod load are considered in this specification.

    Also included are the requirements for the design and rating of enclosed speed reducers wherein the involute gear tooth designs include helical and herringbone gearing. The rating methods and influences identified in this specification are limited to single and multiple stage designs applied to beam pumping units in which the pitch-line velocity of any stage does not exceed 5000 ft/min and the speed of any shaft does not exceed 3600 rpm.

    This standard does not cover chemical properties of materials, installation and maintenance of the equipment, beam type counterbalance units, prime movers and power transmission devices outside the gear reducer, or control systems.

    See Annex A for product is supplied bearing the API Monogram and manufactured at a facility licensed by API.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/dcd56f6c-a55b-470c-bedb-aeee70bebfe2.htm 01-Nov-13
    API SPEC 11IW 1ST ED (R 2008) Specification for Independent Wellhead Equipment; First Edition; Reaffirmed April 2008 1.1 PURPOSE

    This specification was formulated to provide for the availability of safe, dimensionally and functionally interchangeable independent wellhead equipment. The technical content provides requirements for performance, design, materials, testing, inspection, welding, marking, handling, storing and shipping.

    1.2 APPLICATIONS

    1.2.1 Coverage

    This specification covers the independent wellhead equipment utilized for pressure control systems for the production of oil and gas. Specific equipment covered by this specification is listed as follows:

    a. Independent wellheads.

    b. Top connectors.

    c. Tubing and casing slip hangers.

    d. Tubing and cashing mandrel hangers.

    e. Packoffs.

    f. Belled nipples.

    g. Connector flanges.

    h. Stripper adapters.

    The typical equipment nomenclature used in this specification is shown in Figures 1, 2, 3, and 4.

    1.2.2 Service Conditions

    1.2.2.1 General

    Service conditions refer to classifications for pressure, temperature, and the various well-bore fluid and operating conditions.

    1.2.2.2 Pressure Ratings

    Pressure ratings indicate rated working pressures expressed as gage pressure (psig).

    1.2.2.3 Temperature Rating

    Temperature rating indicates the temperature range, from minimum ambient to maximum flowing fluid temperature, expressed in degrees Fahrenheit (degrees F).

    1.2.2.4 Materials Class Rating

    Materials class rating indicates the material of the equipment components.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/8cacad94-2284-472d-ba89-820422350658.htm 01-Jun-00
    API SPEC 11PL 1ST ED (2019) Plunger Lift Lubricators and Related Equipment; First Edition; Effective Date June 1, 2020 This specification provides requirements and guidelines for plunger lift lubricators, which includes plunger catchers as defined herein for use in the petroleum and natural gas industry. Threaded and flanged external connections are covered by the applicable API or proprietary connection design requirements. This specification provides requirements for the functional specification and technical specification, including design requirements (outlet locations, specified and optional), design extensions, design verification and validation, welding, materials, quality controls (QCs), marking, documentation and data control, shipment, and storage.

    This specification does not include control system components, including electrical and electronic devices, installation requirements, field modifications of lubricators, and plunger lift downhole equipment. Additionally, the requirements for the inlet and outlet flange bolting and gaskets are not addressed herein. Equipment and technology that are covered by other API specifications and standards are exempted from this specification. This specification includes five annexes: Annex A (informative), Annexes B through D (normative), and Annex E, which is informative and includes guidelines for plunger lift lubricator use and maintenance.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c4c372b8-b4c0-4f98-8651-c9508822697d.htm 01-Feb-19
    API SPEC 11V1 2ND ED (R 2008) Specification for Gas Lift Equipment; Second Edition; Reaffirmed April 2008 1.1. PURPOSE

    This specification was formulated to provide gas lift valves, reverse flow (check) valves, orifice valves, dummy valves and wireline retrievable valve mandrels (WRVM) that are consistently manufactured to a predictable level of quality. Technical content provides requirements for design, materials, tests and inspecting, welding, marking, storing and shipping. This specification is intended as a quality based specification and does not assure dimensional interchangeability between manufacturers.

    1.2 APPLICATIONS

    1.2.1 Equipment

    This specification is for gas lift valves, reverse flow (check) valves, orifice valves, dummy valves and the WRVM’s used as a receiver for these valves or other devices used to enhance oil well production or treat oil or gas wells. This specification is compiled such that the requirements for gas lift valves and WRVM’s are in separate sections and unless indicated do not overlap requirements.

    1.2.2 Service Classification

    1.2.2.1 Valve Service Class

    For gas lift valve class of service conditions refer to 4.3.3.

    1.2.2.2 WRVM Service Class

    For WRVM class of service conditions refer to 5.1.1.2.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/be56cd3c-3a74-4713-93e0-1c7a221ce8dd.htm 01-Feb-95
    API SPEC 12D 12TH ED (2017) Specification for Field Welded Tanks for Storage of Production Liquids; Twelfth Edition; Effective Date: December 1, 2017 1.1 General

    This specification covers material, design, fabrication, and testing requirements for vertical, cylindrical,aboveground, closed top, welded steel storage tanks in various standard sizes and capacities for internal pressures of approximately atmospheric, not to exceed those listed in Table 5.1, Column 2.

    This specification provides the oil production industry with tanks of adequate safety and reasonable economy for use in the storage of crude petroleum and other liquids commonly handled and stored by the production segment of the industry. This specification is for the convenience of purchasers and manufacturers in ordering and fabricating tanks.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/4b4325fd-8d53-4d01-8738-7d7f6777eea0.htm 01-Jun-17
    API SPEC 12F 13TH ED (2019) Specification for Shop Welded Tanks for Storage of Production Liquids;
       Thirteenth Edition; Effective Date: July 2019
    
    1.1 General

    1.1.1 This specification covers material, design, fabrication, and testing requirements for new shop-fabricated vertical, cylindrical, aboveground, welded steel storage tanks in the standard sizes and capacities, and for internal pressures approximately atmospheric, given in Table 1.

    1.1.2 This specification is designed to provide the oil production industry with tanks of adequate safety and reasonable economy for use in the storage of crude petroleum and other liquids commonly handled and stored by the production segment of the industry. This specification is for the convenience of purchasers and manufacturers in ordering and fabricating tanks.

    1.1.3 Only tanks built to the requirements stated in this specification may be identified as 12F tanks. Tanks built to dimensions other than listed in Table 1 are outside the scope of this specification.

    1.1.4 This specification has requirements given in two alternate systems of units. The manufacturer shall comply with the US Customary (USC) units. The SI unit equivalent is provided for convenience.

    NOTE Per API document style, SI unit values appear first, followed by their USC equivalents in parentheses.

    1.2 Compliance

    1.2.1 The manufacturer is responsible for complying with all the provisions of this specification. The purchaser may make any investigation necessary to satisfy himself or herself of manufacturer compliance and may reject any material that does not comply with this specification. The purchaser may wish to avail himself or herself of this right and furnish their own inspection independently of any supervisory inspection furnished by the manufacturer.

    1.2.2 This specification is not intended to cover storage tanks that are to be erected in areas subject to regulations more stringent than the requirements contained in this specification. When this document is specified for such tanks, it should be followed insofar as it does not conflict with regulatory requirements.

    1.2.3 Once the tank has been placed into service, it should be maintained according to API 12R1, API 653, or an owner program specifically designed for tank maintenance.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fce92c8f-40c7-4108-90d2-ba38757d174c.htm 01-Jan-19
    API SPEC 12J 8TH ED (2008) Specification for Oil and Gas Separators; Eighth Edition; Effective Date: April 1, 2009 1.1 General

    This specification covers minimum requirements for the design, fabrication, and shop testing of oil-field type oil and gas separators and/or oil-gas-water separators used in the production of oil and/or gas, and usually located but not limited to some point on the producing flowline between the wellhead and pipeline. Separators covered by this specification may be vertical, spherical, or single or double barrel horizontal.

    Unless otherwise agreed upon between the purchaser and the manufacturer, the jurisdiction of this specification terminates with the pressure vessel as defined in the Scope of Section VIII, Division 1 of the ASME Boiler and Pressure Vessel Code, hereinafter referred to as the ASME Code. Pressure vessels covered by this specification are normally classified as natural resource vessels by API 510, Pressure Vessel Inspection Code. Separators outside the scope of this specification include centrifugal separators, filter separators, and de-sanding separators.

    1.2 Compliance

    Any manufacturer producing equipment or materials represented as conforming with an API specification is responsible for complying with all the provisions of that specification. API does not represent, warrant or guarantee that such products do in fact conform to the applicable API standard or specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d2abddb2-c7a8-4f88-a556-457c7f56b781.htm 01-Oct-08
    API SPEC 12K 8TH ED (2008) Specification for Indirect Type Oilfield Heaters; Eighth Edition; Effective Date: April 1, 2009 This specification covers minimum requirements for the design, fabrication, and shop testing of oilfield indirect type fired heaters used in the production of oil, gas, and their associated fluids. They are usually located at some point on the producing flow-line between the wellhead and pipeline. Heater components covered by this specification include the pressurized coils, the shell, heater bath, firetube and the firing system.

    Termination of a heater coil shall be at the first bevel when coils are furnished beveled for welding, or the face of the first fitting when fittings are furnished as the inlet or outlet connection to the coil. All fittings and valves between the inlet and outlet of the coil are to be considered within the coil limit.

    Heaters outside the scope of this specification include steam and other vapor generators, reboilers, indirect heaters employing heat media other than water solutions, all types of direct fired heaters, shell-and-tube bundles or electrical heating elements, and coils operating at temperatures less than –20°F.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/fde33c83-e4ec-4997-adf9-76cf3b7db7db.htm 01-Oct-08
    API SPEC 12L 5TH ED (2008) Specification for Vertical and Horizontal Emulsion Treaters; Fifth Edition; Effective Date: April 1, 2009 1.1 General

    This specification covers minimum requirements for material, design, fabrication, and testing of vertical and horizontal emulsion treaters. The jurisdiction of this specification terminates with each pressure vessel as applicable: the emulsion treater with firetube(s) and, if used, the heat exchanger(s) and water siphon. Pressure vessels covered by this specification are classified as natural resource vessels by API 510, Pressure Vessel Inspection Code. An emulsion treater is a pressure vessel used in the oil producing industry for separating oil-water emulsions and gas, and for breaking or resolving emulsified well streams into water and saleable clean oil components. Emulsion treaters are usually equipped with one or more removable firetubes or heat exchange elements through which heat is applied to the water and/or emulsion to aid the emulsion breaking process.

    1.2 Background

    Emulsion treating is normally conducted on crude oil immediately after it is separated from its associated gas in a vessel referred to as a treater or sometimes as a heater treater. High gas-oil ratio wells or those produced by gas lift may require the installation of an oil and gas separator upstream of the treater to remove most of the associated gas before the emulsion enters the treater. Where the water to oil ratio is high, Freewater knockouts may be required upstream of the treater. The function of the treater is to dehydrate (or dewater) the produced crude oil to a specified level of basic sediment and water (BS&W). Oil-water separation may be enhanced by heating, emulsion breaking chemicals, coalescing media, and/or electrostatic fields in vessels sized for substantial liquid residence time. Process considerations are covered in Annex A. Refer to Figure 1, Figure 2 and Figure 3, which show general arrangements of components, piping and instrumentation. (Some of the illustrated features are considered optional.)


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/0f999928-bd63-479e-952f-d906297f2087.htm 01-Oct-08
    API SPEC 14A 12TH ED (2015) Specification for Subsurface Safety Valve Equipment; Twelfth Edition; Effective Date: January 15, 2016 This specification provides the requirements for subsurface safety valves (SSSVs), and the secondary tools as defined herein necessary to operate the features included within them, including all components that establish tolerances and/or clearances that may affect performance or interchangeability of the SSSV components. It includes repair operations and the interface connections to control conduits and/or other equipment, but does not cover the connections to the primary well conduit.

    NOTE The SSSV is an emergency fail-safe flow controlling safety device. The products covered within this specification are installed and operated to the requirements of API 14B.

    This specification does not cover installation, maintenance, control systems for SSSV, computer systems, and control conduits not integral to the downhole SSSV. Also not included are products and capabilities covered under API 19G Parts 1 through 4, API 14L, API 11D1, API 6A, API 17C, API 19V, and the following products: downhole chokes, wellhead plugs, sliding sleeves, downhole well test tools, or casing mounted flow control valves.

    Redress activities for SSSVs and secondary tools are beyond the scope of this specification and included in API 14B.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex N shall apply


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/fdecef4b-9741-43c2-9a66-0c8d141d6672.htm 01-Jan-15
    API SPEC 14A 12TH ED (E1) Specification for Subsurface Safety Valve Equipment; Twelfth Edition; Effective Date: January 15, 2016 This specification provides the requirements for subsurface safety valves (SSSVs),

    and the secondary tools as defined herein necessary to operate the features included within them, including all components that establish tolerances and/or clearances that may affect performance or interchangeability of the SSSV components. It includes repair operations and the interface connections to control conduits and/or other equipment, but does not cover the connections to the primary well conduit.

    NOTE The SSSV is an emergency fail-safe flow controlling safety device. The products covered within this specification are installed and operated to the requirements of API 14B.

    This specification does not cover installation, maintenance, control systems for SSSV, computer systems, and control conduits not integral to the downhole SSSV. Also not included are products and capabilities covered under API 19G Parts 1 through 4, API 14L, API 11D1, API 6A, API 17C, API 19V, and the following products: downhole chokes, wellhead plugs, sliding sleeves, downhole well test tools, or casing mounted flow control valves.

    Redress activities for SSSVs and secondary tools are beyond the scope of this specification and included in API 14B.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex N apply


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/58aa1700-24b1-4eb9-947c-6aa957ed25d1.htm 01-Jan-15
    API SPEC 14A 12TH ED (E1) (A1) Specification for Subsurface Safety Valve Equipment; Twelfth Edition; Effective Date: January 15, 2016 This specification provides the requirements for subsurface safety valves (SSSVs),

    and the secondary tools as defined herein necessary to operate the features included within them, including all components that establish tolerances and/or clearances that may affect performance or interchangeability of the SSSV components. It includes repair operations and the interface connections to control conduits and/or other equipment, but does not cover the connections to the primary well conduit.

    NOTE The SSSV is an emergency fail-safe flow controlling safety device. The products covered within this specification are installed and operated to the requirements of API 14B.

    This specification does not cover installation, maintenance, control systems for SSSV, computer systems, and control conduits not integral to the downhole SSSV. Also not included are products and capabilities covered under API 19G Parts 1 through 4, API 14L, API 11D1, API 6A, API 17C, API 19V, and the following products: downhole chokes, wellhead plugs, sliding sleeves, downhole well test tools, or casing mounted flow control valves.

    Redress activities for SSSVs and secondary tools are beyond the scope of this specification and included in API 14B.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex N apply


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/655e71ef-20c8-4463-99a1-a5caf6f86f85.htm 01-Jan-15
    API SPEC 15HR 3RD ED (2001) Specification for High Pressure Fiberglass Line Pipe; Third Edition; Effective Date: August 1, 2016 1.1 PURPOSE

    1.1.1 This specification was formulated to provide for the availability of safe, dimensionally and functionally interchangeable high pressure fiberglass line pipe with a Specification 15HR Standard Pressure Rating from 500 lbf/in.2 to 5000 lbf/in.2, inclusive, in 250 lbf/in.2 increments. This specification is limited to mechanical connections.

    1.1.2 Technical content provides requirements for performance, design, materials, tests and inspection, marking, handling, storing and shipping.

    1.1.3 Critical components are items of equipment having requirements specified in this document.

    1.2 APPLICATIONS

    1.2.1 Equipment

    This specification covers fiberglass pipe utilized for the production of oil and gas. Specific equipment covered by this specification is listed as follows:

    High pressure line pipe and couplings.

    Fittings.

    Flanges.

    Reducers and adapters.

    1.2.2 Service Conditions

    The standard service conditions for Specification 15HR Standard Pressure Rating are as follows:

    Service life is 20 years.

    Service temperature is 150°F.

    The fluid environment is salt water.

    Axial loads shall include end loads due to pressure and bending, where the radius of curvature of the pipe divided by the outside radius of the pipe shall be greater than or equal to 1200.

    Cyclic pressure variation shall include 3,000 cycles from 0 to 120% of Specification 15HR Standard Pressure Rating. Cyclic pressure variation shall include 109 cycles with an R value of 0.9.

    (R = minimum pressure divided by maximum pressure).

    Service conditions other than the standard Specification 15HR conditions are discussed in 5.1.1 and Appendix G.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/11e33687-f750-43b7-bdb8-cb48a8ae2484.htm 01-Aug-01
    API SPEC 15HR 3RD ED (R 2010) Specification for High Pressure Fiberglass Line Pipe; Third Edition; Reaffirmed, October 2010 1.1 PURPOSE

    1.1.1 This specification was formulated to provide for the availability of safe, dimensionally and functionally interchangeable high pressure fiberglass line pipe with a Specification 15HR Standard Pressure Rating from 500 lbf/in.2 to 5000 lbf/in.2, inclusive, in 250 lbf/in.2 increments. This specification is limited to mechanical connections.

    1.1.2 Technical content provides requirements for performance, design, materials, tests and inspection, marking, handling, storing and shipping.

    1.1.3 Critical components are items of equipment having requirements specified in this document.

    1.2 APPLICATIONS

    1.2.1 Equipment

    This specification covers fiberglass pipe utilized for the production of oil and gas. Specific equipment covered by this specification is listed as follows:

    High pressure line pipe and couplings.

    Fittings.

    Flanges.

    Reducers and adapters.

    1.2.2 Service Conditions

    The standard service conditions for Specification 15HR Standard Pressure Rating are as follows:

    Service life is 20 years.

    Service temperature is 150°F.

    The fluid environment is salt water.

    Axial loads shall include end loads due to pressure and bending, where the radius of curvature of the pipe divided by the outside radius of the pipe shall be greater than or equal to 1200.

    Cyclic pressure variation shall include 3,000 cycles from 0 to 120% of Specification 15HR Standard Pressure Rating. Cyclic pressure variation shall include 109 cycles with an R value of 0.9.

    (R = minimum pressure divided by maximum pressure).

    Service conditions other than the standard Specification 15HR conditions are discussed in 5.1.1 and Appendix G.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/1eda8486-c8ad-4069-acd8-1e3dfd9bdb08.htm 01-Aug-01
    API SPEC 15HR 4TH ED (2016) High-pressure Fiberglass Line Pipe; Fourth Edition; Effective Date: August 1, 2016 1.1 Coverage

    This specification was formulated to provide for the availability of safe, dimensionally, and functionally inter-changeable high-pressure fiberglass line pipe with a pressure rating from 500 lbf/in.2to 5000 lbf/in.2(3.45 MPa to 34.5 MPa), inclusive, in 250 lbf/in.2(1.72 MPa) increments for pipes ≤ than NPS 12 inches and 100 lbf/in.2(0.69 MPa) increments for pipes ˃ than NPS 12 inches. This specification is limited to mechanical connections and the technical content provides requirements for performance, design, materials, tests and inspection, marking, handling, storing, and shipping. Critical components are items of equipment having requirements specified in this document.

    This specification is applicable to rigid pipe components made from thermosetting resins and reinforced with glass fibers. Typical thermosetting resins are epoxy, polyester, vinyl ester, and phenolic. Thermoplastic resins are excluded from the scope of this specification. Any internal liners applied shall be made also from thermosetting resins. Fiberglass line pipe for use in low-pressure systems are covered in API Spec 15LR.

    This specification covers fiberglass pipe utilized for the production of oil and gas. Specific equipment covered by this specification is high-pressure line pipe and couplings, fittings, flanges, and reducers and adapters.

    1.2 Application of the API Monogram

    If product is manufactured at a facility licensed by API and it is intended to be supplied bearing the API Monogram, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/360aa7f0-737f-4432-b6cb-55dc9b9f5cea.htm 01-Aug-16
    API SPEC 15HR 4TH ED (E1) High-pressure Fiberglass Line Pipe; Fourth Edition; Effective Date: August 1, 2016 1.1 Coverage

    This specification was formulated to provide for the availability of safe, dimensionally, and functionally inter-changeable high-pressure fiberglass line pipe with a pressure rating from 500 lbf/in.2to 5000 lbf/in.2(3.45 MPa to 34.5 MPa), inclusive, in 250 lbf/in.2(1.72 MPa) increments for pipes ≤ than NPS 12 inches and 100 lbf/in.2(0.69 MPa) increments for pipes ˃ than NPS 12 inches. This specification is limited to mechanical connections and the technical content provides requirements for performance, design, materials, tests and inspection, marking, handling, storing, and shipping. Critical components are items of equipment having requirements specified in this document.

    This specification is applicable to rigid pipe components made from thermosetting resins and reinforced with glass fibers. Typical thermosetting resins are epoxy, polyester, vinyl ester, and phenolic. Thermoplastic resins are excluded from the scope of this specification. Any internal liners applied shall be made also from thermosetting resins. Fiberglass line pipe for use in low-pressure systems are covered in API Spec 15LR.

    This specification covers fiberglass pipe utilized for the production of oil and gas. Specific equipment covered by this specification is high-pressure line pipe and couplings, fittings, flanges, and reducers and adapters.

    1.2 Application of the API Monogram

    If product is manufactured at a facility licensed by API and it is intended to be supplied bearing the API Monogram, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/b8fed6f6-c608-4712-afe9-5ee258ae4492.htm 01-Aug-16
    API SPEC 15LE 4TH ED (2008) Specification for Polyethylene Line Pipe (PE); Fourth Edition; Effective Date: July 1, 2008 1.1 Purpose

    The purpose of this specification is to provide standards for polyethylene (PE) line pipe suitable for use in conveying oil, gas and non-potable water in underground, above ground and reliner applications for the oil and gas producing industries.

    The standard does not propose to address all of the safety concerns associated with the design, installation or use of products suggested herein. It is the responsibility of the user of the standard to utilize appropriate health and safety considerations.

    All pipe produced under this standard must utilize pressure rated materials, but may be used in pressurized, nonpressure and negative pressure applications. The technical content of this document provides requirements and guidelines for performance, design, materials inspection, dimensions and tolerances, marking, handling, storing and shipping.

    1.2 Applications

    1.2.1 Equipment

    This specification covers polyethylene line pipe utilized for the production and transportation of oil, gas and nonpotable water. The piping is intended for use in new construction, insertion renewal, line extension and repair, of both above ground and buried pipe applications. Specific equipment covered by this specification is listed as follows:

    1) polyethylene line pipe;

    2) polyethylene fittings.

    1.2.2 Service Conditions

    The standard service conditions for the API Spec15LE Standard Pressure Rating are as follows:

    1) HDB is established to 50 years;

    2) service temperature is between –30 ºF and 140 ºF;

    3) the fluid environment is oil, gas and non-potable water;

    4) axial loads shall include end loads due to pressure only. Service conditions other than the standard API Spec 15LE conditions are discussed in Section 5—Design.

    1.3 Unit Conversion A decimal/inch system is the standard for the dimensions shown in this specification. Nominal sizes will continue to be shown as fractions. For the purposes of this specification, the fractions and their decimal equivalents are equal and interchangeable. For SI metric unit equivalents in millimeters (mm), multiply by 25.4 and round to 1 decimal place. Basic metric conversions are described in Annex A.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/5f33cf74-a106-4669-a076-ed560eef11f5.htm 01-Jan-08
    API SPEC 15LE 4TH ED (R 2013) Specification for Polyethylene Line Pipe (PE); Fourth Edition; Effective Date: July 1, 2008; Reaffirmed, October 2013 1.1 Purpose

    The purpose of this specification is to provide standards for polyethylene (PE) line pipe suitable for use in conveying oil, gas and non-potable water in underground, above ground and reliner applications for the oil and gas producing industries.

    The standard does not propose to address all of the safety concerns associated with the design, installation or use of products suggested herein. It is the responsibility of the user of the standard to utilize appropriate health and safety considerations.

    All pipe produced under this standard must utilize pressure rated materials, but may be used in pressurized, nonpressure and negative pressure applications.

    The technical content of this document provides requirements and guidelines for performance, design, materials inspection, dimensions and tolerances, marking, handling, storing and shipping.

    1.2 Applications

    1.2.1 Equipment

    This specification covers polyethylene line pipe utilized for the production and transportation of oil, gas and nonpotable water. The piping is intended for use in new construction, insertion renewal, line extension and repair, of both above ground and buried pipe applications. Specific equipment covered by this specification is listed as follows:

    1) polyethylene line pipe;

    2) polyethylene fittings.

    1.2.2 Service Conditions

    The standard service conditions for the API Spec15LE Standard Pressure Rating are as follows:

    1) HDB is established to 50 years;

    2) service temperature is between –30 °F and 140 °F;

    3) the fluid environment is oil, gas and non-potable water;

    4) axial loads shall include end loads due to pressure only.

    Service conditions other than the standard API Spec 15LE conditions are discussed in Section 5—Design.

    1.3 Unit Conversion

    A decimal/inch system is the standard for the dimensions shown in this specification. Nominal sizes will continue to be shown as fractions. For the purposes of this specification, the fractions and their decimal equivalents are equal and interchangeable. For SI metric unit equivalents in millimeters (mm), multiply by 25.4 and round to 1 decimal place. Basic metric conversions are described in Annex A.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/c08a9e78-7c36-47a2-ae5e-7b744092487c.htm 01-Jan-08
    API SPEC 15LE 4TH ED (R 2018) Specification for Polyethylene Line Pipe (PE); Fourth Edition; Effective Date: July 1, 2008; Reaffirmed, October 2018 1.1 Purpose

    The purpose of this specification is to provide standards for polyethylene (PE) line pipe suitable for use in conveying oil, gas and non-potable water in underground, above ground and reliner applications for the oil and gas producing industries.

    The standard does not propose to address all of the safety concerns associated with the design, installation or use of products suggested herein. It is the responsibility of the user of the standard to utilize appropriate health and safety considerations.

    All pipe produced under this standard must utilize pressure rated materials, but may be used in pressurized, nonpressure and negative pressure applications.

    The technical content of this document provides requirements and guidelines for performance, design, materials inspection, dimensions and tolerances, marking, handling, storing and shipping.

    1.2 Applications

    1.2.1 Equipment

    This specification covers polyethylene line pipe utilized for the production and transportation of oil, gas and nonpotable water. The piping is intended for use in new construction, insertion renewal, line extension and repair, of both above ground and buried pipe applications. Specific equipment covered by this specification is listed as follows:

    1) polyethylene line pipe;

    2) polyethylene fittings.

    1.2.2 Service Conditions

    The standard service conditions for the API Spec15LE Standard Pressure Rating are as follows:

    1) HDB is established to 50 years;

    2) service temperature is between –30 °F and 140 °F;

    3) the fluid environment is oil, gas and non-potable water;

    4) axial loads shall include end loads due to pressure only.

    Service conditions other than the standard API Spec 15LE conditions are discussed in Section 5—Design.

    1.3 Unit Conversion

    A decimal/inch system is the standard for the dimensions shown in this specification. Nominal sizes will continue to be shown as fractions. For the purposes of this specification, the fractions and their decimal equivalents are equal and interchangeable. For SI metric unit equivalents in millimeters (mm), multiply by 25.4 and round to 1 decimal place. Basic metric conversions are described in Annex A.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/cc8b75d2-64c4-4bbc-91c2-79672f030f18.htm 01-Jan-08
    API SPEC 15LR 7TH ED (E1) Specification for Low Pressure Fiberglass Line Pipe; Seventh Edition; Effective Date: February 1, 2002 This specification covers filament wound (FW) and centrifugally cast (CC) fiberglass line pipe and fittings for pipe in diameters up to and including 24 in. in diameter and up to and including 1000 psig cyclic operating pressures. In addition, at the manufacturer's option, the pipe may also be rated for static operating pressures up to 1000 psig. It is recommended that the pipe and fittings be purchased by cyclic pressure rating. The standard pressure ratings range from 150 psig to 300 psig in 50 psig increments, and from 300 psig to 1000 psig in 100 psig increments, based on either cyclic pressure (ref. 5.5.1) or static pressure (ref. 55.2). Quality control tests, hydrostatic mill tests, dimensions, weights, material properties, physical properties, and minimum performance requirements are included.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/190758a2-6a36-4160-94b7-b183488dea80.htm 01-Aug-01
    API SPEC 15LR 7TH ED (E1) (R 2018) Specification for Low Pressure Fiberglass Line Pipe; Seventh Edition; Effective Date: February 1, 2002 This specification covers filament wound (FW) and centrifugally cast (CC) fiberglass line pipe and fittings for pipe in diameters up to and including 24 in. in diameter and up to and including 1000 psig cyclic operating pressures. In addition, at the manufacturer's option, the pipe may also be rated for static operating pressures up to 1000 psig. It is recommended that the pipe and fittings be purchased by cyclic pressure rating. The standard pressure ratings range from 150 psig to 300 psig in 50 psig increments, and from 300 psig to 1000 psig in 100 psig increments, based on either cyclic pressure (ref. 5.5.1) or static pressure (ref. 55.2). Quality control tests, hydrostatic mill tests, dimensions, weights, material properties, physical properties, and minimum performance requirements are included.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/ea9fb1ef-c5d0-4453-b8ac-3e442539999d.htm 01-Aug-01
    API SPEC 15LR 7TH ED (R 2008) Specification for Low Pressure Fiberglass Line Pipe; Seventh Edition; Reaffirmed, May 2008 This specification covers filament wound (FW) and centrifugally cast (CC) fiberglass line pipe and fittings for pipe in diameters up to and including 24 in. in diameter and up to and including 1000 psig cyclic operating pressures. In addition, at the manufacturer's option, the pipe may also be rated for static operating pressures up to 1000 psig. It is recommended that the pipe and fittings be purchased by cyclic pressure rating. The standard pressure ratings range from 150 psig to 300 psig in 50 psig increments, and from 300 psig to 1000 psig in 100 psig increments, based on either cyclic pressure (ref. 5.5.1) or static pressure (ref. 5.5.2). Quality control tests, hydrostatic mill tests, dimensions, weights, material properties, physical properties, and minimum performance requirements are included.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/7ec3235a-4256-4e15-a69a-d6a74293f740.htm 01-Aug-01
    API SPEC 15LR 7TH ED (R 2013) Specification for Low Pressure Fiberglass Line Pipe; Seventh Edition; Reaffirmed, October 2013 This specification covers filament wound (FW) and centrifugally

    cast (CC) fiberglass line pipe and fittings for pipe in diameters up to and including 24 in. in diameter and up to and including 1000 psig cyclic operating pressures. In addition, at the manufacturer's option, the pipe may also be rated for static operating pressures up to 1000 psig. It is recommended that the pipe and fittings be purchased by cyclic pressure rating. The standard pressure ratings range from 150 psig to 300 psig in 50 psig increments, and from 300 psig to 1000 psig in 100 psig increments, based on either cyclic pressure (ref. 5.5.1) or static pressure (ref. 5.5.2). Quality control tests, hydrostatic mill tests, dimensions, weights, material properties, physical properties, and minimum performance requirements are included.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/852a1d9f-f2e1-4afb-96c9-91bdbbf53d2c.htm 01-Aug-01
    API SPEC 15LT 1ST ED (1993) Specification for PVC Lined Steel Tubular Goods; First Edition a. The purpose of this Specification is to provide standards for PVC lined steel pipe or tubing, suitable for use in conveying water and/or oil in the Petroleum Industry.

    b. American Petroleum Institute (API) Specifications are published as aids to the procurement of standardized equipment and materials, as well as instructions to manufacturers of equipment or materials covered by an API Specification. These Specifications are not intended to obviate the need for sound engineering, nor to inhibit in any way anyone from purchasing or producing products to other specifications.

    c The formulation and publication of API Specifications and the API monogram program is not intended in any way to inhibit the purchase of products from companies not licensed to use the API monogram.

    d. API Specifications may be used by anyone desiring to do so, and diligent effort has been made by the Institute to assure the accuracy and reliability of the data contained therein. However, the Institute makes no representation, warranty, or guarantee in connection with the publication of any API Specification and hereby expressly disclaims any liability or responsibility for losses or damage resulting from their use, for any violation of any federal, state or municipal regulation with which an API Specification may conflict, or for the infringement of any patent resulting from the use of an API Specification.

    e. Any Manufacturer marking equipment or materials in conformance with the marking requirements of an API Specification is solely responsible for complying with all the applicable requirements of that Specification. The American Petroleum Institute does not represent, warrant or guarantee that such products do in fact conform to the applicable API Specification.

    f. This Specification for PVC lined steel tubular goods was formulated by the API Production Department Committee on Standardization of Plastic Pipe.

    g. This Standard (supplement) shall become effective on the date printed on the cover but may be used voluntarily from the date of distribution.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/6e2a8ecc-bcb4-48e2-9f14-3528760a300f.htm 01-Jan-93
    API SPEC 15PX 1ST ED (2018) Specification for Crosslinked Polyethylene (PEX) Line Pipe; First Edition This specification covers PEX line pipe utilized for the production and transportation of oil, gas, and nonpotable water. The piping is intended for use in new construction, structural, pressure-rated liner, line extension, and repair of both aboveground and buried pipe applications. Specific equipment covered by this specification is listed as follows:

    a) PEX line pipe;

    b) fittings.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d43b19b4-9231-462f-aba1-1e6fe6b2ba3a.htm 01-Sep-18
    API SPEC 15S 2ND ED (2016) Spoolable Reinforced Plastic Line Pipe; Second Edition; Effective Date: September 1, 2016 1.1 CoverageThis specification provides requirements for the manufacture and qualification of spoolable reinforced plastic line pipe in oilfield and energy applications including transport of multiphase fluids, hydrocarbon gases, hydrocarbon liquids, oilfield production chemicals, and non-potable water. Also included are performance requirements for materials, pipe, and fittings.These products consist of a liner with helically wrapped steel or nonmetallic reinforcing elements and an outer cover. The helical reinforcing elements shall be a single material. Additional non-helical reinforcing elements are acceptable. The spoolable reinforced line pipe under this specification is capable of being spooled for storage, transport and installation. For offshore use, additional requirements may apply and are not within the scope of this document.This specification is confined to pipe and end-fittings and couplings and does not relate to other system components and appurtenances. Where other system components (e.g. elbows, tees, valves) are of conventional construction they will be governed by other applicable codes and practices.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/063480e5-3ce1-4b75-a94c-7fa7051cc9ea.htm 01-Sep-16
    API SPEC 15S 2ND ED (E1) Spoolable Reinforced Plastic Line Pipe; Second Edition; Effective Date: September 1, 2016 1.1 Coverage

    This specification provides requirements for the manufacture and qualification of spoolable reinforced plastic line pipe in oilfield and energy applications including transport of multiphase fluids, hydrocarbon gases, hydrocarbon liquids, oilfield production chemicals, and non-potable water. Also included are performance requirements for materials, pipe, and fittings.

    These products consist of a liner with helically wrapped steel or nonmetallic reinforcing elements and an outer cover. The helical reinforcing elements shall be a single material. Additional non-helical reinforcing elements are acceptable. The spoolable reinforced line pipe under this specification is capable of being spooled for storage, transport and installation. For offshore use, additional requirements may apply and are not within the scope of this document.

    This specification is confined to pipe and end-fittings and couplings and does not relate to other system components and appurtenances. Where other system components (e.g. elbows, tees, valves) are of conventional construction they will be governed by other applicable codes and practices.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/a62dd261-ed64-47ab-9ce2-0ccbab65c8e4.htm 01-Sep-16
    API SPEC 15S 2ND ED (E1) (A1) Spoolable Reinforced Plastic Line Pipe; Second Edition; Effective Date: September 1, 2016 This specification provides requirements for the manufacture and qualification of spoolable reinforced plastic line pipe in oilfield and energy applications including transport of multiphase fluids, hydrocarbon gases, hydrocarbon liquids, oilfield production chemicals, and nonpotable water. Also included are performance requirements for materials, pipe, and fittings.

    These products consist of a liner with helically wrapped steel or nonmetallic reinforcing elements and an outer cover. The helical reinforcing elements shall be a single material. Reinforcement tapes, with either metal wire or non- metallic reinforcement fibers and a matrix material, are considered single material. Additional nonhelical reinforcing elements are acceptable. The spoolable reinforced line pipe under this specification is capable of being spooled for storage, transport, and installation. For offshore use, additional requirements may apply and are not within the scope of this document.

    This specification is confined to pipe and end-fittings and couplings and does not relate to other system components and appurtenances. Where other system components (e.g. elbows, tees, valves) are of conventional construction they will be governed by other applicable codes and practices.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b54ae0cd-4245-4246-ae6e-b596a4674ce6.htm 01-Sep-16
    API SPEC 16A 4TH ED (2017) Specification for Drill-Through Equipment; Fourth Edition; Effective Date: February 1, 2018 This specification defines the requirements for performance, design, materials, testing and inspection, welding, marking, handling, storing, and shipping of drill-through equipment used for drilling for oil and gas. It also defines service conditions in terms of pressure, temperature, and wellbore fluids for which the equipment is designed.

    This specification is applicable to and establishes requirements for the following specific equipment:

    a) ram blowout preventers;

    b) ram blocks, packers and top seals;

    c) annular blowout preventers;

    d) annular packing units;

    e) hydraulic wellbore connectors (wellhead, riser, or LMRP);

    f) drilling spools and spacer spools;

    g) adapters;

    h) mandrels (for wellbore connectors);

    i) loose connections;

    j) clamps.

    Dimensional interchangeability is limited to end and outlet connections.

    A simplified example of drill-through equipment defined by this specification is shown in Figures 1 and 2.

    Repair and remanufacture of 16A equipment is covered in API 16AR, Standard for Repair and Remanufacturing of Drill-through Equipment.

    This specification does not apply to field use or field testing of drill-through equipment.

    If a product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/7e4dafeb-8f39-4084-a007-a51a30d156b7.htm 01-Apr-17
    API SPEC 16A 4TH ED (E1) Specification for Drill-Through Equipment; Fourth Edition; Effective Date: February 1, 2018 This specification defines the requirements for performance, design, materials, testing and inspection,

    welding, marking, handling, storing, and shipping of drill-through equipment used for drilling for oil and gas. It also defines service conditions in terms of pressure, temperature, and wellbore fluids for which the equipment is designed.

    This specification is applicable to and establishes requirements for the following specific equipment:

    a) ram blowout preventers;

    b) ram blocks, packers and top seals;

    c) annular blowout preventers;

    d) annular packing units;

    e) hydraulic wellbore connectors (wellhead, riser, or LMRP);

    f) drilling spools and spacer spools;

    g) adapters;

    h) mandrels (for wellbore connectors);

    i) loose connections;

    j) clamps.

    Dimensional interchangeability is limited to end and outlet connections.

    A simplified example of drill-through equipment defined by this specification is shown in Figures 1 and 2. Repair and remanufacture of 16A equipment is covered in API 16AR, Standard for Repair and Remanufacturing of Drill-through Equipment.

    This specification does not apply to field use or field testing of drill-through equipment.

    If a product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the

    requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/e43966ac-659f-43a5-96b4-d42468761791.htm 01-Apr-17
    API SPEC 16A 4TH ED (E1) (A1) Specification for Drill-Through Equipment; Fourth Edition; Effective Date: February 1, 2018 This specification defines the requirements for performance, design, materials, testing and inspection,

    welding, marking, handling, storing, and shipping of drill-through equipment used for drilling for oil and gas. It also defines service conditions in terms of pressure, temperature, and wellbore fluids for which the equipment is designed.

    This specification is applicable to and establishes requirements for the following specific equipment:

    a) ram blowout preventers;

    b) ram blocks, packers and top seals;

    c) annular blowout preventers;

    d) annular packing units;

    e) hydraulic wellbore connectors (wellhead, riser, or LMRP);

    f) drilling spools and spacer spools;

    g) adapters;

    h) mandrels (for wellbore connectors);

    i) loose connections;

    j) clamps.

    Dimensional interchangeability is limited to end and outlet connections.

    A simplified example of drill-through equipment defined by this specification is shown in Figures 1 and 2. Repair and remanufacture of 16A equipment is covered in API 16AR, Standard for Repair and Remanufacturing of Drill-through Equipment.

    This specification does not apply to field use or field testing of drill-through equipment.

    If a product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the

    requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/60f25d07-bedf-4e30-856a-391b231ca3ca.htm 01-Apr-17
    API SPEC 16A 4TH ED (E1) (E2) (A1) Specification for Drill-Through Equipment; Fourth Edition; Effective Date: April 1, 2018 This specification defines the requirements for performance, design, materials, testing and inspection,welding, marking, handling, storing, and shipping of drill-through equipment used for drilling for oil andgas. It also defines service conditions in terms of pressure, temperature, and wellbore fluids for which theequipment is designed.

    This specification is applicable to and establishes requirements for the following specific equipment:

    a) ram blowout preventers;

    b) ram blocks, packers and top seals;

    c) annular blowout preventers;

    d) annular packing units;

    e) hydraulic wellbore connectors (wellhead, riser, or LMRP);

    f) drilling spools and spacer spools;

    g) adapters;

    h) mandrels (for wellbore connectors);

    i) loose connections;

    j) clamps.

    Dimensional interchangeability is limited to end and outlet connections.

    A simplified example of drill-through equipment defined by this specification is shown in Figures 1 and 2.Repair and remanufacture of 16A equipment is covered in API 16AR, Standard for Repair andRemanufacturing of Drill-through Equipment.

    This specification does not apply to field use or field testing of drill-through equipment.If a product is supplied bearing the API Monogram and manufactured at a facility licensed by API, therequirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d91d9de3-94b2-41ee-9602-1ebcb8b87dcd.htm 01-Apr-17
    API SPEC 16A 4TH ED (E1) (E2) (E3) (A1) Specification for Drill-Through Equipment; Fourth Edition; Effective Date: April 1, 2018 This specification defines the requirements for performance, design, materials, testing and inspection,

    welding, marking, handling, storing, and shipping of drill-through equipment used for drilling for oil and gas. It also defines service conditions in terms of pressure, temperature, and wellbore fluids for which the equipment is designed.

    This specification is applicable to and establishes requirements for the following specific equipment:

    a) ram blowout preventers;

    b) ram blocks, packers and top seals;

    c) annular blowout preventers;

    d) annular packing units;

    e) hydraulic wellbore connectors (wellhead, riser, or LMRP);

    f) drilling spools and spacer spools;

    g) adapters;

    h) mandrels (for wellbore connectors);

    i) loose connections;

    j) clamps.

    Dimensional interchangeability is limited to end and outlet connections.

    A simplified example of drill-through equipment defined by this specification is shown in Figures 1 and 2. Repair and remanufacture of 16A equipment is covered in API 16AR, Standard for Repair and Remanufacturing of Drill-through Equipment.

    This specification does not apply to field use or field testing of drill-through equipment.

    If a product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the

    requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9ec6b6c8-7b0a-417c-b3b2-2cf601806763.htm 01-Apr-17
    API SPEC 16C 1ST ED (R 2001) Specification for Choke and Kill Systems; First Edition; Reaffirmed, July 2001 This specification was formulated to provide for safe and functionally interchangeable surface and subsea choke and kill systems equipment utilized for drilling oil and gas wells. Other parts of the Choke and Kill System not specifically addressed in this document shall be in accordance with the applicable sections of this specification.

    Technical content provides the minimum requirements for performance, design, materials, welding, testing, inspection, storing and shipping.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/12725658-fae2-4ce4-a990-f206e56ec637.htm 28-Jan-93
    API SPEC 16C 1ST ED (R 2010) Specification for Choke and Kill Systems; First Edition; Reaffirmed, July 2010 This specification was formulated to provide for safe and functionally interchangeable surface and subsea choke and kill systems equipment utilized for drilling oil and gas wells. Other parts of the Choke and Kill System not specifically addressed in this document shall be in accordance with the applicable sections of this specification.

    Technical content provides the minimum requirements for performance, design, materials, welding, testing, inspection, storing and shipping.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/29f74cef-730f-4b2d-8cfe-78ef5cfcf7ce.htm 29-Jan-93
    API SPEC 16C 2ND ED (2015) Choke and Kill Equipment; Second Edition This specification establishes the minimum requirements for the design and manufacture of the following types of new equipment:

    a) articulated choke and kill lines;

    b) choke and kill manifold buffer chamber;

    c) choke and kill manifold assembly;

    d) drilling choke actuators;

    e) drilling choke controls;

    f) drilling chokes;

    g) flexible choke and kill lines;

    h) union connections used in choke and kill assemblies; i) rigid choke and kill lines;

    j) swivel unions used in choke and kill equipment.

    These requirements were formulated to provide for safe and functionally interchangeable surface and subsea choke and kill system equipment utilized for drilling oil and gas wells.

    Technical content provides the minimum requirements for performance, design, materials, welding, testing, inspection, storing, and shipping.

    See 4.2 for requirements on additional components that may be included in choke and kill system equipment.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b80cc77d-df25-4edc-99c0-ab5f4ea81748.htm 01-Mar-15
    API SPEC 16C 2ND ED (E1) (E2) (E3) Choke and Kill Equipment; Second Edition 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 interpretation of the content of this publication or comments and questions concerning the procedures under which this publication was developed should be directed in writing to the Director of Standards, American Petroleum Institute, 1220 L Street, NW, Washington, DC 20005. Requests for permission to reproduce or translate all or any part of the material published herein should also be addressed to the director.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/22686727-a878-4660-9020-31c7ac2619be.htm 06-Aug-16
    API SPEC 16C 2ND ED (E1) (E2) (E3) (E4) (A1) Choke and Kill Equipment; Second Edition This specification establishes the minimum requirements for the design and manufacture of the following types of new equipment:

    a) articulated choke and kill lines;

    b) choke and kill manifold buffer chamber;

    c) choke and kill manifold assembly;

    d) drilling choke actuators;

    e) drilling choke controls;

    f) drilling chokes;

    g) flexible choke and kill lines;

    h) union connections used in choke and kill assemblies;

    i) rigid choke and kill lines;

    j) swivel unions used in choke and kill equipment.

    These requirements were formulated to provide for safe and functionally interchangeable surface and subsea choke and kill system equipment utilized for drilling oil and gas wells. Technical content provides the minimum requirements for performance, design, materials, welding, testing, inspection, storing, and shipping.

    See 4.2 for requirements on additional components that may be included in choke and kill system equipment.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/72115624-9eec-4cd5-844d-c8c58cb1a3b8.htm 01-Nov-15
    API SPEC 16D 1ST ED (1993) Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment; First Edition These specifications establish design standards for systems, that are used to control blowout preventers (BOPs) and associated valves that control well pressure during drilling operations. The design standards applicable to subsystems and components do not include material selection and manufacturing process details but may serve as an aid to purchasing. Although diverters are not considered well control devices, their controls are often incorporated as part of the BOP control system. Thus, control systems for diverter equipment are included herein. Control systems for drilling well control equipment typically employ stored energy in the form of pressurized hydraulic fluid (power fluid) to operate (open and close) the BOP stack components. Each operation of a BOP or other well component is referred to as a control function. The control system equipment and circuitry vary generally in accordance with the application and environment. The specifications provided herein describe the following control system categories:

    a. Control systems for surface mounted BOP stacks. These systems are typically simple return-to-reservoir hydraulic control systems consisting of a reservoir for storing hydraulic fluid, pump equipment for pressurizing the hydraulic fluid, accumulator banks for storing power fluid and manifolding, piping and control valves for transmission of control fluid to the BOP stack functions.

    b. Control systems for subsea BOP stacks (common elements). Remote control of a seafloor BOP stack requires specialized equipment. Some of the control system elements are common to virtually all subsea control systems, regardless of the means used for function signal transmission.

    c. Discrete hydraulic control systems for subsea BOP stacks. In addition to the equipment required for surface-mounted BOP stacks, discrete hydraulic subsea control systems use umbilical hose bundles for transmission of hydraulic pilot signals subsea. Also used are dual subsea control pods mounted on the LMRP (lower marine riser package), and housing pilot operated control valves for directing power fluid to the BOP stack functions. Spent water-based hydraulic fluid is usually vented subsea. Hose reels are used for storage and deployment of the umbilical hose bundles. The use of dual subsea pods and umbilicals affords backup security.

    d. Electro-hydraulic/multiplex control systems for subsea BOP stacks. For deepwater operations, transmission subsea of electric/optical (rather than hydraulic) signals affords short response times. Electro-hydraulic systems employ multi-conductor cables, having a pair of wires dedicated to each function to operate subsea solenoid valves which send hydraulic pilot signals to the control valves that operate the BOP stack functions. Multiplex control systems employ serialized communications with multiple commands being transmitted over individual conductor wires or fibers. Electronic/optical data processing and transmission are used to provide the security of codifying and confirming functional command signals so that a stray signal, cross talk or a short circuit should not execute a function.

    e. Control systems for diverter equipment. Direct hydraulic controls are commonly used for operation of the surface mounted diverter unit. Associated valves may be hydraulically or pneumatically operated.

    f. Auxiliary equipment control systems and interfaces. For floating drilling operations, various auxiliary functions such as the telescopic joint packer, 30 in. latch/pin connection, riser annulus gas control equipment, etc., require operation by the control system. These auxiliary equipment controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.

    g. Emergency disconnect sequenced systems (EDS). (Optional) An EDS provides automatic LMRP disconnect when specific emergency conditions occur on a floating drilling vessel. These controls, though not specifically described herein,shall be subject to the relevant specifications provided herein and requirements for similar equipment.

    h. Backup Systems (Optional). When the subsea control system is inaccessible or non-functional, an independent control system may be used to operate selected well control, disconnect, and/or recovery functions. They include acoustic control systems, ROV (Remotely Operated Vehicle) operated control systems and LMRP recovery systems. For surface control systems, a reserve supply of pressurized nitrogen gas can serve as a backup means to operate functions in the event that the pump system power supply is lost. These controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.

    i. Special deepwater/harsh environment features (Optional). For deepwater/harsh environment operations, particularly where multiplex BOP controls and dynamic positioning of the vessel are used, special control system features may be employed. These controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fa464645-1191-407e-9e58-7ede06e1089e.htm 01-Mar-93
    API SPEC 16D 2ND ED (2004) Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment; Second Edition; Effective Date: January 1, 2005 These specifications establish design standards for systems, that are used to control blowout preventers (BOPs) and associated valves that control well pressure during drilling operations. The design standards applicable to subsystems and components do not include material selection and manufacturing process details but may serve as an aid to purchasing. Although diverters are not considered well control devices, their controls are often incorporated as part of the BOP control system. Thus, control systems for diverter equipment are included herein. Control systems for drilling well control equipment typically employ stored energy in the form of pressurized hydraulic fluid (power fluid) to operate (open and close) the BOP stack components. Each operation of a BOP or other well component is referred to as a control function. The control system equipment and circuitry vary generally in accordance with the application and environment. The specifications provided herein describe the following control system categories:

    a. Control systems for surface mounted BOP stacks. These systems are typically simple return-to-reservoir hydraulic control systems consisting of a reservoir for storing hydraulic fluid, pump equipment for pressurizing the hydraulic fluid, accumulator banks for storing power fluid and manifolding, piping and control valves for transmission of control fluid to the BOP stack functions.

    b. Control systems for subsea BOP stacks (common elements). Remote control of a seafloor BOP stack requires specialized equipment. Some of the control system elements are common to virtually all subsea control systems, regardless of the means used for function signal transmission.

    c. Discrete hydraulic control systems for subsea BOP stacks. In addition to the equipment required for surface-mounted BOP stacks, discrete hydraulic subsea control systems use umbilical hose bundles for transmission of hydraulic pilot signals subsea. Also used are dual subsea control pods mounted on the LMRP (lower marine riser package), and housing pilot operated control valves for directing power fluid to the BOP stack functions. Spent water-based hydraulic fluid is usually vented subsea. Hose reels are used for storage and deployment of the umbilical hose bundles. The use of dual subsea pods and umbilicals affords backup security.

    d. Electro-hydraulic/multiplex control systems for subsea BOP stacks. For deepwater operations, transmission subsea of electric/optical (rather than hydraulic) signals affords short response times. Electro-hydraulic systems employ multi-conductor cables, having a pair of wires dedicated to each function to operate subsea solenoid valves which send hydraulic pilot signals to the control valves that operate the BOP stack functions. Multiplex control systems employ serialized communications with multiple commands being transmitted over individual conductor wires or fibers. Electronic/optical data processing and transmission are used to provide the security of codifying and confirming functional command signals so that a stray signal, cross talk or a short circuit should not execute a function.

    e. Control systems for diverter equipment. Direct hydraulic controls are commonly used for operation of the surface mounted diverter unit. Associated valves may be hydraulically or pneumatically operated.

    f. Auxiliary equipment control systems and interfaces. For floating drilling operations, various auxiliary functions such as the telescopic joint packer, 30 in. latch/pin connection, riser annulus gas control equipment, etc., require operation by the control system. These auxiliary equipment controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.

    g. Emergency disconnect sequenced systems (EDS). (Optional) An EDS provides automatic LMRP disconnect when specific emergency conditions occur on a floating drilling vessel. These controls, though not specifically described herein,shall be subject to the relevant specifications provided herein and requirements for similar equipment.

    h. Backup Systems (Optional). When the subsea control system is inaccessible or non-functional, an independent control system may be used to operate selected well control, disconnect, and/or recovery functions. They include acoustic control systems, ROV (Remotely Operated Vehicle) operated control systems and LMRP recovery systems. For surface control systems, a reserve supply of pressurized nitrogen gas can serve as a backup means to operate functions in the event that the pump system power supply is lost. These controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.

    i. Special deepwater/harsh environment features (Optional). For deepwater/harsh environment operations, particularly where multiplex BOP controls and dynamic positioning of the vessel are used, special control system features may be employed. These controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/3a5b279f-ecfb-4a2d-b911-d2585255da86.htm 01-Jul-04
    API SPEC 16D 2ND ED (R 2013) Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment; Second Edition; Effective Date: January 1, 2005; Reaffirmed, August 2013 These specifications establish design standards for systems, that are used to

    control blowout preventers (BOPs) and associated valves that control well pressure during drilling operations. The design standards applicable to subsystems and components do not include material selection and manufacturing process details but may serve as an aid to purchasing. Although diverters are not considered well control devices, their controls are often incorporated as part of the BOP control system. Thus, control systems for diverter equipment are included herein. Control systems for drilling well control equipment typically employ stored energy in the form of pressurized hydraulic fluid (power fluid) to operate (open and close) the BOP stack components. Each operation of a BOP or other well component is referred to as a control function. The control system equipment and circuitry vary generally in accordance with the application and environment. The specifications provided herein describe the following control system categories:

    a. Control systems for surface mounted BOP stacks. These systems are typically simple return-to-reservoir hydraulic control systems consisting of a reservoir for storing hydraulic fluid, pump equipment for pressurizing the hydraulic fluid, accumulator banks for storing power fluid and manifolding, piping and control valves for transmission of control fluid to the BOP stack functions.

    b. Control systems for subsea BOP stacks (common elements). Remote control of a seafloor BOP stack requires specialized equipment. Some of the control system elements are common to virtually all subsea control systems, regardless of the means used for function signal transmission.

    c. Discrete hydraulic control systems for subsea BOP stacks. In addition to the equipment required for surface-mounted BOP stacks, discrete hydraulic subsea control systems use umbilical hose bundles for transmission of hydraulic pilot signals subsea. Also used are dual subsea control pods mounted on the LMRP (lower marine riser package), and housing pilot operated control valves for directing power fluid to the BOP stack functions. Spent water-based hydraulic fluid is usually vented subsea. Hose reels are used for storage and deployment of the umbilical hose bundles. The use of dual subsea pods and umbilicals affords backup security.

    d. Electro-hydraulic/multiplex control systems for subsea BOP stacks. For deepwater operations, transmission subsea of electric/ optical (rather than hydraulic) signals affords short response times. Electro-hydraulic systems employ multi-conductor cables, having a pair of wires dedicated to each function to operate subsea solenoid valves which send hydraulic pilot signals to the control valves that operate the BOP stack functions. Multiplex control systems employ serialized communications with multiple commands being transmitted over individual conductor wires or fibers. Electronic/optical data processing and transmission are used to provide the security of codifying and confirming functional command signals so that a stray signal, cross talk or a short circuit should not execute a function.

    e. Control systems for diverter equipment. Direct hydraulic controls are commonly used for operation of the surface mounted diverter unit. Associated valves may be hydraulically or pneumatically operated.

    f. Auxiliary equipment control systems and interfaces. For floating drilling operations, various auxiliary functions such as the telescopic joint packer, 30 in. latch/pin connection, riser annulus gas control equipment, etc., require operation by the control system. These auxiliary equipment controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.

    g. Emergency disconnect sequenced systems (EDS). (Optional) An EDS provides automatic LMRP disconnect when specific emergency conditions occur on a floating drilling vessel. These controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.

    h. Backup Systems (Optional). When the subsea control system is inaccessible or non-functional, an independent control system may be used to operate selected well control, disconnect, and/or recovery functions. They include acoustic control systems, ROV (Remotely Operated Vehicle) operated control systems and LMRP recovery systems. For surface control systems, a reserve supply of pressurized nitrogen gas can serve as a backup means to operate functions in the event that the pump system power supply is lost. These controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.

    i. Special deepwater/harsh environment features (Optional). For deepwater/harsh environment operations, particularly where multiplex BOP controls and dynamic positioning of the vessel are used, special control system features may be employed. These controls, though not specifically described herein, shall be subject to the relevant specifications provided herein and requirements for similar equipment.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ff7c671b-b732-428c-abea-d19fae3ee5f5.htm 01-Jul-04
    API SPEC 16D 3RD ED (2018) Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment; Third Edition; Effective Date: May 2019 These specifications establish minimum design standards for systems used to control blowout preventers (BOPs) and associated valves that control well pressure during drilling operations. The requirements in this specification apply to the following control system categories:

    a) control systems for land based and surface-mounted BOP stacks;

    b) discrete hydraulic control systems for subsea BOP stacks;

    c) electro-hydraulic/multiplex (MUX) control systems for subsea BOP stacks;

    d) emergency control systems for subsea BOP stacks;

    e) secondary control systems for subsea BOP stacks; and

    f) control systems for diverter equipment.

    The design standards applicable to subsystems and components do not include material selection and manufacturing process details but may serve as an aid to purchasing. Although diverters are not considered well control devices, their controls are often incorporated as part of the BOP control system. Thus, control systems for diverter equipment are included.

    Control systems for drilling well control equipment typically employ stored energy in the form of pressurized hydraulic fluid (power fluid) to operate (open and close) the BOP stack components. Each operation of a BOP or other well component is referred to as a control function. The design of control system equipment and circuitry varies in accordance with the application and environment.

    See Annex A for information on the API Monogram Program.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/f67b887e-6ea5-4b30-8bd3-c88fbfd611db.htm 01-Nov-18
    API SPEC 16F 1ST ED (A1) (A2) (R 2010) Specification for Marine Drilling Riser Equipment; First Edition; Effective Date: February 1, 2005; Reaffirmed, August 2010 1.1 PURPOSE

    These specifications establish standards of performance and quality for the design, manufacture, and fabrication of marine drilling riser equipment used in conjunction with a subsea Blowout Preventer (BOP) Stack.

    1.2 COVERAGE

    This specification provides the requirements for the following major subsystems in the marine drilling riser system:

    a. Riser tensioner equipment.*

    b. Flex/ball joints.*

    c. Choke, kill and auxiliary lines.

    d. Drape hoses and jumper lines for flex/ball joints.

    e. Telescopic joint (slip joint) and tensioner ring.*

    f. Riser joints.*

    g. Buoyancy equipment* (only syntactic foam modules eligible for API Monogram).

    h. Riser running equipment.*

    i. Special riser system components.

    j. Lower riser adapter.*

    Note: Only those subsystems above that are marked with an asterisk may be considered for API monogramming.

    Section 4 of the specification gives a general description of each of these components listed above. Section 5 provides general design requirements for riser components. Section 6 addresses materials, including the riser pipe. Paragraph 6.13 covers welding of couplings to riser pipe and welding of pipe to pipe. It also covers other types of welds used in the fabrication of riser equipment.

    Sections 7 through 16 address the following for each component:

    a. Service classification.

    b. Design.

    c. Materials.

    d. Dimensions.

    e. Process control.

    f. Testing.

    g. Marking.

    h. Packing/Shipping.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/62173e26-a9ac-4b74-8bbe-6342650a416d.htm 01-Aug-04
    API SPEC 16F 1ST ED (A1) (R 2010) Specification for Marine Drilling Riser Equipment; First Edition; Effective Date: February 1, 2005; Reaffirmed, August 2010 1.1 PURPOSE

    These specifications establish standards of performance and quality for the design, manufacture, and fabrication of marine drilling riser equipment used in conjunction with a subsea Blowout Preventer (BOP) Stack.

    1.2 COVERAGE

    This specification provides the requirements for the following major subsystems in the marine drilling riser system:

    a. Riser tensioner equipment.*

    b. Flex/ball joints.*

    c. Choke, kill and auxiliary lines.

    d. Drape hoses and jumper lines for flex/ball joints.

    e. Telescopic joint (slip joint) and tensioner ring.*

    f. Riser joints.*

    g. Buoyancy equipment* (only syntactic foam modules eligible for API Monogram).

    h. Riser running equipment.*

    i. Special riser system components.

    j. Lower riser adapter.*

    Note: Only those subsystems above that are marked with an asterisk may be considered for API monogramming.

    Section 4 of the specification gives a general description of each of these components listed above. Section 5 provides general design requirements for riser components. Section 6 addresses materials, including the riser pipe. Paragraph 6.13 covers welding of couplings to riser pipe and welding of pipe to pipe. It also covers other types of welds used in the fabrication of riser equipment.

    Sections 7 through 16 address the following for each component:

    a. Service classification.

    b. Design.

    c. Materials.

    d. Dimensions.

    e. Process control.

    f. Testing.

    g. Marking.

    h. Packing/Shipping.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/057a8658-f427-46b1-9a1c-46eee11961b4.htm 01-Aug-04
    API SPEC 16F 1ST ED (R 2010) Specification for Marine Drilling Riser Equipment; First Edition; Effective Date: February 1, 2005; Reaffirmed, August 2010 1.1 PURPOSE These specifications establish standards of performance and quality for the design, manufacture, and fabrication of marine drilling riser equipment used in conjunction with a subsea Blowout Preventer (BOP) Stack. 1.2 COVERAGE This specification provides the requirements for the following major subsystems in the marine drilling riser system: a. Riser tensioner equipment.* b. Flex/ball joints.* c. Choke, kill and auxiliary lines. d. Drape hoses and jumper lines for flex/ball joints. e. Telescopic joint (slip joint) and tensioner ring.* f. Riser joints.* g. Buoyancy equipment* (only syntactic foam modules eligible for API Monogram). h. Riser running equipment.* i. Special riser system components. j. Lower riser adapter.* Note: Only those subsystems above that are marked with an asterisk may be considered for API monogramming. Section 4 of the specification gives a general description of each of these components listed above. Section 5 provides general design requirements for riser components. Section 6 addresses materials, including the riser pipe. Paragraph 6.13 covers welding of couplings to riser pipe and welding of pipe to pipe. It also covers other types of welds used in the fabrication of riser equipment. Sections 7 through 16 address the following for each component: a. Service classification. b. Design. c. Materials. d. Dimensions. e. Process control. f. Testing. g. Marking. h. Packing/Shipping.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/0b81622b-7e3f-4c55-a27a-bffdb7ee54a0.htm 01-Aug-04
    API SPEC 16F 2ND ED (2017) Specification for Marine Drilling Riser Equipment; Second Edition; Effective Date: May 1, 2018 This specification establishes standards of performance and quality for the design, manufacture, and

    fabrication of marine drilling riser equipment used in conjunction with a subsea blowout preventer (BOP) stack.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b83e7279-7cee-4eb4-b4b0-96d4a44a14ef.htm 01-Nov-17
    API SPEC 16F 2ND ED (E1) Specification for Marine Drilling Riser Equipment; Second Edition; Effective Date: May 1, 2018 This specification establishes standards of performance and quality for the design, manufacture, and

    fabrication of marine drilling riser equipment used in conjunction with a subsea blowout preventer (BOP) stack.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/419669b2-2091-4e4a-80b0-6fffed9beac4.htm 01-Nov-17
    API SPEC 16R 1ST ED (1997) Specification for Marine Drilling Riser Couplings; First Edition; Effective Date: June 1, 1997 1.1 Purpose

    This specification pertains to the design, rating, manufacturing and testing of marine drilling riser couplings. Coupling capacity ratings are established to enable the grouping of coupling models according to their maximum stresses developed under specific levels of loading, regardless of manufacturer or method of make-up. This specification relates directly to API Recommended Practice 16Q, which pertains to the design, selection, and operation of the marine drilling riser system as a whole.

    1.2 Organization

    This specification is organized into distinct sections for easy reference. Section 3 contains a description of the function of marine riser couplings, along with the definition of relevant terms. Section 4 includes service classifications and design criteria. Materials and welding requirements are included in Section 5 and dimensions in Section 6. Section 7 covers quality control. Design qualification testing requirements are spelled out in Section 8, and product marking requirements are provided in Section 9. Section 10 defines requirements for operation and Maintenance manuals. Appendixes A, B, and C provide analysis, testing, and design, information.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/3fae099a-c968-4196-9007-7c8365497d73.htm 01-Jan-97
    API SPEC 16R 1ST ED (R 2010) Specification for Marine Drilling Riser Couplings; First Edition; Effective Date: June 1, 1997; Reaffirmed, August 2010 1.1 Purpose This specification pertains to the design, rating, manufacturing and testing of marine drilling riser couplings. Coupling capacity ratings are established to enable the grouping of coupling models according to their maximum stresses developed under specific levels of loading, regardless of manufacturer or method of make-up. This specification relates directly to API Recommended Practice 16Q, which pertains to the design, selection, and operation of the marine drilling riser system as a whole.

    1.2 Organization This specification is organized into distinct sections for easy reference. Section 3 contains a description of the function of marine riser couplings, along with the definition of relevant terms. Section 4 includes service classifications and design criteria. Materials and welding requirements are included in Section 5 and dimensions in Section 6. Section 7 covers quality control. Design qualification testing requirements are spelled out in Section 8, and product marking requirements are provided in Section 9. Section 10 defines requirements for operation and Maintenance manuals. Appendixes A, B, and C provide analysis, testing, and design, information.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/71342476-4835-423a-bf15-abe942bf83e4.htm 01-Jan-97
    API SPEC 16RCD 1ST ED (R 2013) Specification for Drill Through Equipment—Rotating Control Devices; First Edition; Effective Date: March 10, 2016; Reaffirmed, October 2013 1.1 PURPOSE

    This specification is formulated to provide for the availability of safe and functionally interchangeable rotating control devices (RCDs) utilized in air drilling, drilling operations for oil and gas, and in geothermal drilling operations.

    Technical content provides requirements for design, performance, materials, tests and inspection, welding, marking, handling, storing, and shipping. This specification does not apply to field use or field-testing of RCDs.

    Critical components are those parts having requirements specified in this document.

    1.2 APPLICATIONS

    1.2.1 Equipment

    Specific equipment covered by this specification is listed as follows:

    a. Active, passive and hybrid rotating control devices. Figures 1, 2 and 3 illustrate a surface BOP stack-up with each type of RCD installed.

    b. RCD bearing assemblies including metallic and non-metallic parts.

    c. RCD packer units (active and passive types).

    d. RCD housing clamps.

    1.2.2 Interchangeability

    Dimensional interchangeability is limited to end and outlet connections per API Spec 6A and API Spec 16A.

    1.2.3 Service Conditions

    Service conditions refer to classifications for pressure, temperature, and wellbore fluids listed in 4.2 for which the equipment will be designed.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ed9ef6e1-0059-4b32-8441-ad46302c30d8.htm 01-Feb-05
    API SPEC 16RCD 2ND ED (2015) Specification for Rotating Control Devices; Second Edition; Effective Date: March 10, 2016 1.1 Purpose

    This specification is developed to provide for the safe and functionally interchangeable rotating control devices (RCDs) utilized in air drilling, drilling operations for oil and gas, and in geothermal drilling operations.

    Technical content provides requirements for design, performance, materials, tests and inspection, welding, marking, handling, storing, and shipping. This specification does not apply to field use or field-testing of RCDs.

    Critical components are those parts having requirements specified in this document.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.

    1.2 Applications

    1.2.1 Equipment

    An RCD is considered a complete system when comprised of subcomponents that allows for rotation and axial movement of drill string while simultaneously containing wellbore pressure. Specific equipment covered by this specification includes but not limited to:

    a)active, passive, and hybrid rotating control devices illustrate a surface BOP stack-up with each type of RCD installed);

    b)RCD bearing assemblies including metallic and non-metallic parts;

    c)RCD packer units (active and passive types);

    d)RCD housing clamps or locking mechanisms.

    1.2.2 Interchangeability

    Dimensional interchangeability is limited to end and outlet connections per API 6A and API 16A.

    1.2.3 Service Conditions

    Service conditions refer to classifications for pressure, temperature, and wellbore fluids listed in 4.2 for which the equipment is designed.

    1.3 Product Specification

    This specification establishes requirements for products listed in 1.2.1.

    1.4 Units and Dimensioning

    For the purposes of this specification, the decimal/inch system is the standard for the dimensions shown. API size designation is shown as fractions. For the purposes of this specification, the fractions and their decimal equivalents are equal and interchangeable.

    1.5 Metric Conversions

    Metric conversions are described in Annex G of API 16A, and Annex F of this document.

    1.6 Annexes

    Annexes to this specification are not identified as requirements. They are included only as guidelines or information.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/1bfee383-d131-4100-9653-a8f4230d4bdc.htm 01-Mar-16
    API SPEC 17D 1ST ED (S1) (S2) (R 2003) Specification for Subsea Wellhead and Christmas Tree Equipment; First Edition; Effective Date: February 1, 2013 [for Valve and Actuator Design Validation (Test Requirements) Only] and November 1, 2011 [for All Other Requirements]; Reaffirmed, November 2003 This specification was formulated to provide for the availability of safe, dimensionally and functionally interchangeable subsea wellhead, mudline, and tree equipment.

    The technical content provides requirements for performance, design, materials, testing, inspection, welding, marking, handling, storing and shipping.

    Critical components are those parts having requirements specified in this document. Rework and repair of used equipment are beyond the scope of this specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/5ef6fd44-a3e9-482d-a2e7-8dac2d1845f7.htm 30-Oct-92
    API SPEC 17E 5TH ED (2017) Specification for Subsea Umbilicals; Fifth Edition; Effective Date: January 15, 2018 This document specifies requirements and gives recommendations for the design, material selection, manufacture, design verification, testing, installation, and operation of umbilicals and associated ancillary equipment for the petroleum and natural gas industries. Ancillary equipment does not include topside hardware. Topside hardware refers to any hardware that is not permanently attached to the umbilical, above the topside hang-off termination.

    This document applies to umbilicals containing components, such as electrical cables, optical fibers, thermoplastic hoses, and metallic tubes, either alone or in combination.

    This document applies to umbilicals for static or dynamic service, with surface–surface, surface–subsea, and subsea–subsea routings.

    This document does not apply to the associated component connectors, unless they affect the performance of the umbilical or that of its ancillary equipment.

    This document applies only to tubes with the following dimensions:

    — wall thickness, t 6 mm (0.2 in.);

    — internal diameter, ID 50.8 mm (2 in.).

    NOTE Tubular products with dimensions greater than these can be regarded as pipeline/line pipe, and therefore designed and manufactured according to a recognized pipeline/line pipe standard.

    This document does not apply to a tube or hose rated lower than 7 MPa (1015 psi).

    This document applies to electrical cables for rated voltages from 1kV (Um = 1.2kV) up to 30kV (Um = 36kV).

    If a product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/2d8c6c9b-e883-4acc-b00c-dc6022d716f6.htm 01-Jul-17
    API SPEC 17E 5TH ED (A1) Specification for Subsea Umbilicals; Fifth Edition; Effective Date: January 15, 2018 This document specifies requirements and gives recommendations for the design, material selection, manufacture, design verification, testing, installation, and operation of umbilicals and associated ancillary equipment for the petroleum and natural gas industries. Ancillary equipment does not include topside hardware. Topside hardware refers to any hardware that is not permanently attached to the umbilical, above the topside hang-off termination.

    This document applies to umbilicals containing components, such as electrical cables, optical fibers, thermoplastic hoses, and metallic tubes, either alone or in combination.

    This document applies to umbilicals for static or dynamic service, with surface–surface, surface–subsea, and subsea–subsea routings.

    This document does not apply to the associated component connectors, unless they affect the performance of the umbilical or that of its ancillary equipment.

    This document applies only to tubes with the following dimensions:

    — wall thickness, t 6 mm (0.2 in.);

    — internal diameter, ID 50.8 mm (2 in.).

    NOTE Tubular products with dimensions greater than these can be regarded as pipeline/line pipe, and therefore designed and manufactured according to a recognized pipeline/line pipe standard.

    This document does not apply to a tube or hose rated lower than 7 MPa (1015 psi).

    This document applies to electrical cables for rated voltages from 1kV (Um = 1.2kV) up to 30kV (Um = 36kV).

    If a product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/564ebe3c-923f-460c-b4c8-5f6b58c48c19.htm 01-Jul-17
    API SPEC 17J 4TH ED (2014) Specification for Unbonded Flexible Pipe; Fourth Edition; Effective Date: November 4, 2014 API 17J defines the technical requirements for safe, dimensionally and

    functionally interchangeable flexible pipes that are designed and manufactured to uniform standards and criteria. Minimum requirements are specified for the design, material selection, manufacture, testing, marking, and packaging of flexible pipes, with reference to existing codes and standards where applicable. See API 17B for guidelines on the use of flexible pipes.

    API 17J applies to unbonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. API 17J does not cover flexible pipes of bonded structure. API 17J does not apply to flexible pipe ancillary components. Guidelines on flexible pipe ancillary components are given in API 17L1, API 17L2, and other API documents.

    API 17J does not apply to flexible pipes that include nonmetallic tensile and pressure armor wires.

    The applications addressed by API 17J are sweet and sour service production, including export and injection applications. Production products include oil, gas, water, and injection chemicals. API 17J applies to both static and dynamic flexible pipes used as flowlines, risers, and jumpers. API 17J does not apply to flexible pipes for use in choke and kill line applications. Annex H of API 17B provides recommendations for the application of fiber reinforced polymer materials for pressure armor and tensile armor in unbonded flexible pipe.

    NOTE 1 See API 16C for choke and kill line applications.

    NOTE 2 API 17K provides guidelines for bonded flexible pipe.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/2b0553a7-b309-4f15-9e2b-db3e1ff22e94.htm 01-May-14
    API SPEC 17K 3RD ED (2017) Specification for Bonded Flexible Pipe; Third Edition; Effective Date: February 1, 2018 This specification defines the technical requirements for safe, dimensionally and functionally interchangeable bonded flexible pipes that are designed and manufactured to uniform standards and criteria. See Figure 1 for an explanatory figure on typical bonded flexible pipe.

    Minimum requirements are specified for the design, material selection, manufacture, testing, marking, and packaging of bonded flexible pipes, with reference to existing codes and standards where applicable. See API 17B for guidelines on the use of flexible pipes. Refer to API 17L1 and API 17L2 for the specification and recommended practice for ancillary equipment including buoyancy, bend limiters, bell mouths, and non-integral stand-alone bend stiffeners.

    This specification applies to bonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings or integrated flanges attached to both ends. API 17K does not cover flexible pipes of unbonded structure. See API 17J for guidance on unbonded flexible pipes.

    This specification can be applied to flexible pipes that include nonmetallic reinforcing layers. This specification can be applied to a bonded construction pipe that includes a material or layer construction that is covered in API 17J.

    Supplementary requirements for loading and discharge hoses can be found in GMPHOM provided they do not contradict those of API 17K.

    The applications addressed by API 17K are for sweet and sour service production, including export and injection and seawater intake applications. Production products include oil, gas, water, and injection chemicals. This specification applies to both static and dynamic flexible pipes used as flowlines, risers, jumpers, and offshore loading and discharge hoses.

    This specification does not apply to flexible pipe ancillary components. Guidelines for ancillary components are given in API 17L1 and API 17L2. This specification does not apply to flexible pipes for use in choke and kill-line applications. See API 16C for guidance on choke and kill-line applications. This specification can be applied to flexible pipes for pile hammer, gas flare, water supply, and jetting applications, though no effort was made to address the specific and unique technological aspects relating to each of these requirements.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/b9cb33b6-4526-4db1-8686-d41c9baf7520.htm 01-Aug-17
    API SPEC 17L1 1ST ED (2013) Specification for Flexible Pipe Ancillary Equipment; First Edition This specification defines the technical requirements for safe, dimensionally and functionally interchangeable flexible pipe ancillary equipment that is designed and manufactured to uniform standards and criteria.

    Minimum requirements are specified for the design, material selection, manufacture, testing, documentation, marking and packaging of flexible pipe ancillary equipment, with reference to existing codes and standards where applicable. See API 17L2 for guidelines on the use of ancillary equipment.

    The applicability relating to a specific item of ancillary equipment is stated at the beginning of the particular section for the ancillary equipment in question. This specification applies to the following flexible pipe ancillary equipment:

    — bend stiffeners;

    — bend restrictors;

    — bellmouths;

    — buoyancy modules and ballast modules;

    — subsea buoys;

    — tethers for subsea buoys and tether clamps;

    — riser and tether bases;

    — clamping devices;

    — piggy-back clamps;

    — repair clamps;

    — I/J-tube seals;

    — pull-in heads/installation aids;

    — connectors;

    — load-transfer devices;

    — mechanical protection;

    — fire protection.

    This specification may be used for bonded flexible pipe ancillary equipment, though any requirements specific to these applications are not addressed.

    The applicability of requirements to umbilicals is indicated in the applicable sections of this specification for the ancillary equipment in question.

    This specification does not cover flexible pipe ancillary equipment beyond the connector, with the exception of riser bases and load-transfer devices. Therefore this document does not cover turret structures or I-tubes and J-tubes for example.In addition, this document does not cover flexible pipe storage devices such as reels, for example.

    This specification is intended to cover ancillary equipment made from several material types, including metallic, polymer and composite materials. It may also refer to material types for particular ancillary components that are not commonly used for such components currently, but may be adopted more frequently in the future.

    This specification applies to ancillary equipment used in association with the flexible pipe applications listed in API 17B, API 17J, and API 17K.

    Annexes to this specification are intended only as guidelines or for information.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/c63be5bb-c0c3-472d-93eb-2afaed19ef33.htm 01-Mar-13
    API SPEC 17L1 1ST ED (E1) Specification for Flexible Pipe Ancillary Equipment; First Edition This specification defines the technical requirements for safe, dimensionally and functionally interchangeable flexible pipe ancillary equipment that is designed and manufactured to uniform standards and criteria.

    Minimum requirements are specified for the design, material selection, manufacture, testing, documentation, marking and packaging of flexible pipe ancillary equipment, with reference to existing codes and standards where applicable. See API 17L2 for guidelines on the use of ancillary equipment.

    The applicability relating to a specific item of ancillary equipment is stated at the beginning of the particular section for the ancillary equipment in question.

    This specification applies to the following flexible pipe ancillary equipment:

    — bend stiffeners;

    — bend restrictors;

    — bellmouths;

    — buoyancy modules and ballast modules; — subsea buoys;

    — tethers for subsea buoys and tether clamps;

    — riser and tether bases;

    — clamping devices;

    — piggy-back clamps;

    — repair clamps;

    — I/J-tube seals;

    — pull-in heads/installation aids;

    — connectors;

    — load-transfer devices;

    — mechanical protection;

    — fire protection.

    This specification may be used for bonded flexible pipe ancillary equipment, though any requirements specific to these applications are not addressed.

    The applicability of requirements to umbilicals is indicated in the applicable sections of this specification for the ancillary equipment in question.

    This specification does not cover flexible pipe ancillary equipment beyond the connector, with the exception of riser bases and load-transfer devices. Therefore this document does not cover turret structures or I-tubes and J-tubes for example. In addition, this document does not cover flexible pipe storage devices such as reels, for example.

    This specification is intended to cover ancillary equipment made from several material types, including metallic, polymer and composite materials. It may also refer to material types for particular ancillary components that are not commonly used for such components currently, but may be adopted more frequently in the future.

    This specification applies to ancillary equipment used in association with the flexible pipe applications listed in API 17B, API 17J, and API 17K.

    Annexes to this specification are intended only as guidelines or for information.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/7ec4dc98-e30d-484f-945c-ba49c51407b0.htm 01-Mar-13
    API SPEC 17L1 1ST ED (E1) (E2) Specification for Flexible Pipe Ancillary Equipment; First Edition This specification defines the technical requirements for safe, dimensionally and functionally interchangeable flexible pipe ancillary equipment that is designed and manufactured to uniform standards and criteria.

    Minimum requirements are specified for the design, material selection, manufacture, testing, documentation, marking and packaging of flexible pipe ancillary equipment, with reference to existing codes and standards where applicable. See API 17L2 for guidelines on the use of ancillary equipment.

    The applicability relating to a specific item of ancillary equipment is stated at the beginning of theparticular section for the ancillary equipment in question.

    This specification applies to the following flexible pipe ancillary equipment:

    — bend stiffeners;

    — bend restrictors;

    — bellmouths;

    — buoyancy modules and ballast modules;

    — subsea buoys;

    — tethers for subsea buoys and tether clamps;

    — riser and tether bases;

    — clamping devices;

    — piggy-back clamps;

    — repair clamps;

    — I/J-tube seals;

    — pull-in heads/installation aids;

    — connectors;

    — load-transfer devices;

    — mechanical protection;

    — fire protection.

    This specification may be used for bonded flexible pipe ancillary equipment, though any requirements specific to these applications are not addressed.

    The applicability of requirements to umbilicals is indicated in the applicable sections of this specification for the ancillary equipment in question.

    This specification does not cover flexible pipe ancillary equipment beyond the connector, with the exception of riser bases and load-transfer devices. Therefore this document does not cover turret structures or I-tubes and J-tubes for example. In addition, this document does not cover flexible pipe storage devices such as reels, for example.

    This specification is intended to cover ancillary equipment made from several material types, including metallic, polymer and composite materials. It may also refer to material types for particular ancillary components that are not commonly used for such components currently, but may be adopted more frequently in the future.

    This specification applies to ancillary equipment used in association with the flexible pipe applications listed in API 17B, API 17J, and API 17K.

    Annexes to this specification are intended only as guidelines or for information.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/780f5efd-db3c-4710-b49f-9a5102962838.htm 01-Nov-15
    API SPEC 19CI 1ST ED (2019) Downhole Chemical Injection Devices and Related Equipment; First Edition 1 Scope

    This specification provides requirements for chemical injection devices intended for use in the worldwide petroleum and natural gas industry. This includes requirements for specifying, selecting, design verification, validation testing, manufacturing, quality-control, testing, and preparation for shipping of chemical injection devices as defined herein. These requirements include in-line debris screen systems, single-use shearable/ frangible devices, and performance testing and calibration procedures.

    The installation and retrieval of chemical Injection devices and systems is outside the scope of this document (see API 19G2 and API 19G3). This document does not include requirements for mandrels, carriers, running, pulling, and kick-over tools, handling tools and latches, injection lines, fittings, control line connectors, clamps, chemicals and chemical delivery systems. Service, repair or redress of used chemical Injection devices is outside of the scope of this document.

    Validation and functional testing within this specification is performed using water as the testing medium. Design validation in conformance with this specification may not provide assurance that a chemical injection device/ product will perform in a specific well, due to the variety and potential contamination of the injected chemicals.

    Included in this specification are Annex B through Annex G (normative) and Annex A and Annex H (informative). If a product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the provisions of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/bdf8a283-8eef-4ba2-8e00-ce6c91301340.htm 01-Jun-19
    API SPEC 19G1 2ND ED (2019) Side-Pocket Mandrels; Second Edition This specification provides requirements for side-pocket mandrels used in the petroleum and natural gas industry. This specification includes specifying, selecting, designing, manufacturing, quality control, testing, and preparation for shipping of side-pocket mandrels.

    This specification addresses standard side-pocket mandrel designs as well as high pressure and/or high temperature (HPHT) equipment rated greater than 103.43 MPa (15,000 psi) and/or greater than 177 °C (350 °F) wellbore conditions as proffered by API 1PER15K-1.

    This specification does not address nor include requirements for end connections between the side-pocket mandrels and the well conduit. The installation and retrieval of side-pocket mandrels is outside the scope of this specification. Additionally, this specification does not include specifications for center-set mandrels, mandrels that employ or support tubing-retrievable flow control devices or side-pocket mandrels that incorporate non-metallic materials for pressure containment.

    This specification does not include gas-lift or any other flow-control valves or devices, latches, and/or associated wire line equipment that can or cannot be covered in other API specifications.

    The side-pocket mandrels to which this specification refers are independent devices that can accept installation of flow control or other devices down-hole.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/cba9fe86-3cc7-48bf-bc86-b7b6e19dfcb7.htm 01-Feb-19
    API SPEC 19G1 2ND ED (E1) Side-Pocket Mandrels; Second Edition This specification provides requirements for side-pocket mandrels used in the petroleum and natural gas industry. This specification includes specifying, selecting, designing, manufacturing, quality control, testing, and preparation for shipping of side-pocket mandrels.

    This specification addresses standard side-pocket mandrel designs as well as high pressure and/or high temperature (HPHT) equipment rated greater than 103.43 MPa (15,000 psi) and/or greater than 177 °C (350 °F) wellbore conditions as proffered by API 1PER15K-1.

    This specification does not address nor include requirements for end connections between the side-pocket mandrels and the well conduit. The installation and retrieval of side-pocket mandrels is outside the scope of this specification. Additionally, this specification does not include specifications for center-set mandrels, mandrels that employ or support tubing-retrievable flow control devices or side-pocket mandrels that incorporate non-metallic materials for pressure containment.

    This specification does not include gas-lift or any other flow-control valves or devices, latches, and/or associated wire line equipment that can or cannot be covered in other API specifications.

    The side-pocket mandrels to which this specification refers are independent devices that can accept installation of flow control or other devices down-hole.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/3463ab89-089c-43c0-8eed-9d983b103571.htm 01-Feb-19
    API SPEC 19G1 2ND ED (E1) (E2) Side-Pocket Mandrels; Second Edition 1 Scope

    This specification provides requirements for side-pocket mandrels used in the petroleum and natural gas industry. This specification includes specifying, selecting, designing, manufacturing, quality control, testing, and preparation for shipping of side-pocket mandrels.

    This specification addresses standard side-pocket mandrel designs as well as high pressure and/or high temperature (HPHT) equipment rated greater than 103.43 MPa (15,000 psi) and/or greater than 177 °C (350 °F) wellbore conditions as proffered by API 1PER15K-1.

    This specification does not address nor include requirements for end connections between the side-pocket mandrels and the well conduit. The installation and retrieval of side-pocket mandrels is outside the scope of this specification. Additionally, this specification does not include specifications for center-set mandrels, mandrels that employ or support tubing-retrievable flow control devices or side-pocket mandrels that incorporate non-metallic materials for pressure containment.

    This specification does not include gas-lift or any other flow-control valves or devices, latches, and/or associated wire line equipment that can or cannot be covered in other API specifications.

    The side-pocket mandrels to which this specification refers are independent devices that can accept installation of flow control or other devices down-hole.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/47a59260-5aa6-4b46-bdc5-0249d07c8e37.htm 01-Jul-19
    API SPEC 19LH 1ST ED (2019) Liner Hanger Equipment; First Edition 1 Scope

    This specification provides requirements for conventional and expandable liner systems, including liner hangers, liner packers, liner hanger packers, tie-back/polished-bore receptacles (TBR/PBRs), seal assemblies, setting adaptors/ sleeves, and running/setting tools as defined herein for use in the oil and natural gas industry. This specification provides minimum requirements for the functional specification and technical specification, including design, design verification and validation, materials, quality control, documentation and data control, repair, shipment, and storage.

    Products covered by this specification apply only to applications within a conduit. Installation and field maintenance are outside the scope of this specification. Also not covered in this specification are casing crossover subs, expandable tubulars and expandable connections, end connections to the liner, cementing aids, liner wiper plugs and drill pipe darts, landing collars, float equipment, wellhead/casing hanger, sub-mudline suspension equipment, and cementing heads. Products covered by other API specifications are not in the scope of this specification.

    Requirements for the API Monogram program are contained in Annex A.

    This specification includes normative Annexes E, F, and H and informative Annexes A, B, C, D, and G.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/87f66e1b-d69d-4198-8f96-7008bcba7f19.htm 01-Jun-19
    API SPEC 19OH 1ST ED (2018) Openhole Isolation Equipment; First Edition; Effective Date, July 2018 http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/e9282611-2617-4069-be2a-e6502ab20dfa.htm 01-Jan-18
    API SPEC 19TT 1ST ED (2016) Specification for Downhole Well

    Test Tools and Related Equipment; First Edition

    This specification provides the requirements for downhole well test tools and related equipment as they are defined herein for use in the petroleum and natural gas industries. Included are the requirements for design, design validation, manufacturing, functional evaluation, quality, handling, storage, and service centers. Tools utilized in downhole well test operations include tester valves, circulating valves, well testing packers, safety joints, well testing safety valves, testing surface safety valves (TSSVs), slip joints, jars, work string tester valves, sampler carriers, gauge carriers, drain valves, related equipment, and tool end connections.

    This specification does not cover open hole well test tools, downhole gauges, samplers, surface equipment, subsea safety equipment, perforating equipment and accessories, pup joints external to well test tool assemblies, work string and its connections, conveyance or intervention systems, installation, control and monitoring conduits, and surface control systems.

    A downhole well test is an operation deploying a temporary completion in a well to safely acquire dynamic rates, formation pressure/temperature, and formation fluid data. Downhole well test tools are also used in operations of well perforating, well shut-ins, circulation control of fluids, and stimulation activities. This document covers the downhole tools used to perform these operations; however, the operational requirements of performing these operations are not included.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a4ac8bb4-c601-4822-bf5a-486cc7db7bb6.htm 01-Oct-16
    API SPEC 19V 2ND ED (2019) Subsurface Completion Isolation (Barrier) Valves and Related Equipment; Second Edition; Effective Date November 2019 This specification provides the requirements for subsurface completion isolation (barrier) valves (SCIV) and related equipment as they are defined herein for use in the petroleum and natural gas industries. Included are the requirements for design, design validation grades, quality levels, manufacturing, functional evaluation, repair, redress, handling, and storage. SCIVs provide a means of isolating the formation or creating a blockage in the tubular to facilitate the performance of pre- and/or post-production/injection operational activities in the well. Additional requirements for HPHT products are included in Annex I.

    When closed, the SCIV provides an obstacle or impediment to flow and/or pressure from above and/or below and a means of isolating the formation within a conduit. The SCIV is not designed as an emergency or fail-safe flow-controlling safety device.

    This specification does not cover installation and maintenance, control systems such as computer systems, and control conduits not integral to the SCIV. Also not included are products covered under ISO 17078, ISO 16070, ISO 14310, ISO 10432, ISO 10423, and the following products: downhole chokes, wellhead plugs, sliding sleeves, casing-mounted flow-control valves, injection valves, well-condition-activated valves, or drill-stem test tools. This specification does not cover the end connections to the well conduit.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/983b49bd-db77-43a2-8a05-e9a58408967c.htm 01-May-19
    API SPEC 19V 2ND ED (E1) Subsurface Completion Isolation (Barrier) Valves and Related Equipment; Second Edition; Effective Date November 2019 1 Scope

    This specification provides the requirements for subsurface completion isolation (barrier) valves (SCIV) and related equipment as they are defined herein for use in the petroleum and natural gas industries. Included are the requirements for design, design validation grades, quality levels, manufacturing, functional evaluation, repair, redress, handling, and storage. SCIVs provide a means of isolating the formation or creating a blockage in the tubular to facilitate the performance of pre- and/or post-production/injection operational activities in the well.

    Additional requirements for HPHT products are included in Annex I.

    When closed, the SCIV provides an obstacle or impediment to flow and/or pressure from above and/or below and a means of isolating the formation within a conduit. The SCIV is not designed as an emergency or fail-safe flow-controlling safety device.

    This specification does not cover installation and maintenance, control systems such as computer systems, and control conduits not integral to the SCIV. Also not included are products covered under ISO 17078, ISO 16070, ISO 14310, ISO 10432, ISO 10423, and the following products: downhole chokes, wellhead plugs, sliding sleeves, casing-mounted flow-control valves, injection valves, well-condition-activated valves, or drill-stem test tools. This specification does not cover the end connections to the well conduit.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8f5c0385-5701-4299-986a-aa9ffa24d318.htm 01-Sep-19
    API SPEC 20A 1ST ED (2012) Carbon Steel, Alloy Steel, Stainless Steel, and Nickel Base Alloy Castings for Use in the Petroleum and Natural Gas Industry; First Edition 1.1 Purpose

    This standard specifies requirements for the design, foundry qualification, production, marking and documentation of carbon steel, alloy steel, stainless steel and nickel base alloy castings used in the petroleum and natural gas industries when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance.

    1.2 Applicability

    This standard applies to castings used in the manufacture of pressure containing, pressure controlling and primary load bearing components. Castings manufactured in accordance with this API Standard may be produced using any industry standard casting method.

    1.3 Casting Specification Levels (CSL)

    This standard establishes requirements for four casting specification levels (CSL). These four CSL designations define different levels of cast product technical, quality and qualification requirements. See Annex A for additional information on purchasing API 20A castings.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/93d16589-c9e0-4c3f-a208-96e8fd0f33ca.htm 01-Mar-12
    API SPEC 20A 1ST ED (A1) Carbon Steel, Alloy Steel, Stainless Steel, and Nickel Base Alloy Castings for Use in the Petroleum and Natural Gas Industry; First Edition 1.1 Purpose

    This standard specifies requirements for the design, foundry qualification, production, marking and documentation of carbon steel, alloy steel, stainless steel and nickel base alloy castings used in the petroleum and natural gas industries when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance.

    1.2 Applicability

    This standard applies to castings used in the manufacture of pressure containing, pressure controlling and primary load bearing components. Castings manufactured in accordance with this API Standard may be produced using any industry standard casting method.

    1.3 Casting Specification Levels (CSL)

    This standard establishes requirements for four casting specification levels (CSL). These four CSL designations define different levels of cast product technical, quality and qualification requirements. See Annex A for additional information on purchasing API 20A castings.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/382bfe4c-9c92-4b49-a651-59e51744ff4e.htm 01-Mar-12
    API SPEC 20A 1ST ED (A1) (A2) Carbon Steel, Alloy Steel, Stainless Steel, and Nickel Base Alloy Castings for Use in the Petroleum and Natural Gas Industry; First Edition 1.1 Purpose

    This standard specifies requirements for the design, foundry qualification, production, marking and documentation of carbon steel, alloy steel, stainless steel and nickel base alloy castings used in the petroleum and natural gas industries when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance.

    1.2 Applicability

    This standard applies to castings used in the manufacture of pressure containing, pressure controlling and primary load bearing components. Castings manufactured in accordance with this API Standard may be produced using any industry standard casting method.

    1.3 Casting Specification Levels (CSL)

    This standard establishes requirements for four casting specification levels (CSL). These four CSL designations define different levels of cast product technical, quality and qualification requirements. See Annex A for additional information on purchasing API 20A castings.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/b84bc46b-2aef-4682-8232-04f18e776f9c.htm 01-Mar-12
    API SPEC 20A 1ST ED (A1) (A2) (E1) Carbon Steel, Alloy Steel, Stainless Steel, and Nickel Base Alloy Castings for Use in the Petroleum and Natural Gas Industry; First Edition 1.1 Purpose

    This standard specifies requirements for the design, foundry qualification, production, marking and documentation of carbon steel, alloy steel, stainless steel and nickel base alloy castings used in the petroleum and natural gas industries when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance.

    1.2 Applicability

    This standard applies to castings used in the manufacture of pressure containing, pressure controlling and primary load bearing components. Castings manufactured in accordance with this API Standard may be produced using any industry standard casting method.

    1.3 Casting Specification Levels (CSL)

    This standard establishes requirements for four casting specification levels (CSL). These four CSL designations define different levels of cast product technical, quality and qualification requirements. See Annex A for additional information on purchasing API 20A castings.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ffe4b158-5ae4-419d-8d77-db470a95341c.htm 01-Mar-12
    API SPEC 20A 2ND ED (2017) Carbon Steel, Alloy Steel, Stainless Steel, and Nickel Base Alloy Castings for Use in the Petroleum and Natural Gas Industry; Second Edition; Effective Date: February 1, 2017 This specification identifies requirements for the foundry qualification, production, design, marking and documentation of carbon steel, alloy steel, stainless steel, and nickel-base alloy castings used in the petroleum and natural gas industries when referenced by an applicable API product standard or otherwise specified as a requirement for compliance.

    This specification applies to castings used in the manufacture of pressure containing, pressure-controlling, and primary load-bearing components. Castings manufactured in accordance with this API Standard may be produced using any industry standard casting method.

    This specification provides manufacturers with a fixed methodology to examine a qualification casting and to compare the results of that examination to a defined set of acceptance criteria. The results of the qualification testing by material grouping are then used to establish a baseline Casting Specification Level (CSL) for subsequently produced castings.

    This specification also provides manufacturers with a fixed production testing methodology to determine if subsequently produced castings conform to the minimum requirements for the intended CSL. The intent is that the production castings meet the minimum CSL requirements established during qualification testing by material grouping and/or the minimum CSL specified by the purchaser.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/ac5e2083-5c7b-4c40-8664-311c2e1d5bd6.htm 01-Aug-17
    API SPEC 20A 2ND ED (A1) Carbon Steel, Alloy Steel, Stainless Steel, and Nickel Base Alloy Castings for Use in the Petroleum and Natural Gas Industry; Second Edition; Effective Date: February 1, 2017 This specification identifies requirements for the foundry qualification, production, design, marking and documentation of carbon steel, alloy steel, stainless steel, and nickel-base alloy castings used in the petroleum and natural gas industries when referenced by an applicable API product standard or otherwise specified as a requirement for compliance.

    This specification applies to castings used in the manufacture of pressure containing, pressure-controlling, and primary load-bearing components. Castings manufactured in accordance with this API Standard may be produced using any industry standard casting method.

    This specification provides manufacturers with a fixed methodology to examine a qualification casting and to compare the results of that examination to a defined set of acceptance criteria. The results of the qualification testing by material grouping are then used to establish a baseline Casting Specification Level (CSL) for subsequently produced castings.

    This specification also provides manufacturers with a fixed production testing methodology to determine if subsequently produced castings conform to the minimum requirements for the intended CSL. The intent is that the production castings meet the minimum CSL requirements established during qualification testing by material grouping and/or the minimum CSL specified by the purchaser.

    If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/2a494e9b-20de-43e2-8aef-2285a6e8dd95.htm 01-Sep-18
    API SPEC 20B 1ST ED (2013) Open Die Shaped Forgings for Use in the Petroleum and Natural Gas Industry; First Edition 1.1 Purpose

    This API standard specifies requirements for the qualification and production of open die shaped forgings for use in API service components in the petroleum and natural gas industries when referenced by an applicable equipment standard or otherwise specified as a requirement for compliance.

    1.2 Applicability

    This API standard is applicable to equipment used in the oil and natural gas industries where service conditions warrant the use of individually shaped open die forgings, including rolled rings. Examples include pressure containing or load bearing components. Forged bar, rolled bar, and forgings from which multiple parts are removed are beyond the scope of this specification.

    1.3 Forging Specification Levels (FSL) This API standard establishes requirements for four forging specification levels (FSL). These four FSL designations define different levels of forged product technical, quality and qualification requirements.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/1b28e68f-6844-4dea-9855-f3f5d91096af.htm 01-Apr-13
    API SPEC 20B 1ST ED (E1) Open Die Shaped Forgings for Use in the Petroleum and Natural Gas Industry; First Edition 1.1 Purpose

    This API standard specifies requirements for the qualification and production of open die shaped forgings for use in API service components in the petroleum and natural gas industries when referenced by an applicable equipment standard or otherwise specified as a requirement for compliance.

    1.2 Applicability

    This API standard is applicable to equipment used in the oil and natural gas industries where service conditions warrant the use of individually shaped open die forgings, including rolled rings. Examples include pressure containing or load bearing components. Forged bar, rolled bar, and forgings from which multiple parts are removed are beyond the scope of this specification.

    1.3 Forging Specification Levels (FSL)

    This API standard establishes requirements for four forging specification levels (FSL). These four FSL designations define different levels of forged product technical, quality and qualification requirements.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0d295e57-1e1d-4569-916b-0828ae872468.htm 01-Apr-13
    API SPEC 20C 1ST ED (2009) Closed Die Forgings for Use in the Petroleum and Natural Gas Industry; First Edition; Effective Date: November 1, 2016 1.1 Purpose

    This standard specifies requirements and gives recommendations for the design, qualification, and production of closed die forgings for use in API service components in the petroleum and natural gas industries when referenced by an applicable equipment standard or otherwise specified as a requirement for compliance.

    1.2 Applicability

    This standard is applicable to equipment used in the oil and natural gas industries where service conditions warrant the use of closed die forgings. Examples include pressure-containing or load-bearing components.

    1.3 Forging Specification Levels (FSLs)

    This standard establishes requirements for four FSLs. These FSL designations define different levels of forged product technical, quality, and qualification requirements.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/0465cdd3-de6a-440b-950c-6cad4f4f29af.htm 01-Oct-09
    API SPEC 20C 1ST ED (A1) Closed Die Forgings for Use in the Petroleum and Natural Gas Industry; First Edition; Effective Date: November 1, 2016 1.1 Purpose

    This standard specifies requirements and gives recommendations for the design, qualification, and production of closed die forgings for use in API service components in the petroleum and natural gas industries when referenced by an applicable equipment standard or otherwise specified as a requirement for compliance.

    1.2 Applicability

    This standard is applicable to equipment used in the oil and natural gas industries where service conditions warrant the use of closed die forgings. Examples include pressure-containing or load-bearing components.

    1.3 Forging Specification Levels (FSLs)

    This standard establishes requirements for four FSLs. These FSL designations define different levels of forged product technical, quality, and qualification requirements.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/1a309ec3-b9ff-48fe-a1bf-744a13d7a320.htm 01-Oct-09
    API SPEC 20E 1ST ED (2012) Alloy and Carbon Steel Bolting for Use in the Petroleum and Natural Gas Industries; First Edition 1.1 Purpose

    This standard specifies requirements for the qualification, production and documentation of alloy and carbon steel bolting used in the petroleum and natural gas industries.

    1.2 Applicability

    This standard applies when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance. An annex for supplemental requirements that may be invoked by the purchaser is included.

    1.3 Bolting Specification Levels (BSL)

    This standard establishes requirements for three bolting specification levels (BSL). These three BSL designations define different levels of technical, quality and qualification requirements, BSL-1, BSL-2, and BSL-3. The BSLs are numbered in increasing levels of severity in order to reflect increasing technical, quality and qualification criteria.

    1.4 Bolting Types

    This standard covers the following finished product forms, processes, and sizes:

    a) machined studs;

    b) machined bolts, screws and nuts;

    c) cold formed bolts, screws, and nuts (BSL-1 only);

    d) hot formed bolts and screws < 1.5 in. (38.1 mm) nominal diameter;

    e) hot formed bolts and screws ≥ 1.5 in. (38.1 mm) nominal diameter;

    f) roll threaded studs, bolts, and screws < 1.5 in. (38.1 mm) diameter;

    g) roll threaded studs, bolts, and screws ≥ 1.5 in. (38.1 mm) diameter;

    h) hot formed nuts < 1.5 in. (38.1 mm) nominal diameter;

    i) hot formed nuts ≥ 1.5 in. (38.1 mm) nominal diameter.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/e3195e72-4cce-44a2-b396-25d27d510078.htm 01-Aug-12
    API SPEC 20E 1ST ED (E1) Alloy and Carbon Steel Bolting for Use in the Petroleum and Natural Gas Industries; First Edition 1.1 Purpose

    This standard specifies requirements for the qualification, production and documentation of alloy and carbon steel bolting used in the petroleum and natural gas industries.

    1.2 Applicability

    This standard applies when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance. An annex for supplemental requirements that may be invoked by the purchaser is included.

    1.3 Bolting Specification Levels (BSL)

    This standard establishes requirements for three bolting specification levels (BSL). These three BSL designations define different levels of technical, quality and qualification requirements, BSL-1, BSL-2, and BSL-3. The BSLs are numbered in increasing levels of severity in order to reflect increasing technical, quality and qualification criteria.

    1.4 Bolting Types

    This standard covers the following finished product forms, processes, and sizes:

    a) machined studs;

    b) machined bolts, screws and nuts;

    c) cold formed bolts, screws, and nuts (BSL-1 only);

    d) hot formed bolts and screws < 1.5 in. (38.1 mm) nominal diameter;

    e) hot formed bolts and screws ≥ 1.5 in. (38.1 mm) nominal diameter;

    f) roll threaded studs, bolts, and screws < 1.5 in. (38.1 mm) diameter;

    g) roll threaded studs, bolts, and screws ≥ 1.5 in. (38.1 mm) diameter;

    h) hot formed nuts < 1.5 in. (38.1 mm) nominal diameter;

    i) hot formed nuts ≥ 1.5 in. (38.1 mm) nominal diameter.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d30f42ca-e146-4274-bea8-eb46c38c77a1.htm 01-Aug-12
    API SPEC 20E 2ND ED (2017) Alloy and Carbon Steel Bolting for Use in the Petroleum and Natural Gas Industries; Second Edition 1.1 Purpose

    This standard specifies requirements for the qualification, production and documentation of alloy and carbon steel bolting used in the petroleum and natural gas industries.

    1.2 Applicability

    This standard applies when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance. An annex for supplemental requirements that may be invoked by the purchaser is included.

    1.3 Bolting Specification Levels (BSL)

    This standard establishes requirements for three bolting specification levels (BSL). These three BSL designations define different levels of technical, quality and qualification requirements, BSL-1, BSL-2, and BSL-3. The BSLs are numbered in increasing levels of severity in order to reflect increasing technical, quality and qualification criteria.

    1.4 Bolting Types

    This standard covers the following finished product forms, processes, and sizes:

    a) machined studs;

    b) machined bolts, screws and nuts;

    c) cold formed bolts, screws, and nuts (BSL-1 only);

    d) hot formed bolts and screws < 1.5 in. (38.1 mm) nominal diameter;

    e) hot formed bolts and screws ≥ 1.5 in. (38.1 mm) nominal diameter;

    f) roll threaded studs, bolts, and screws < 1.5 in. (38.1 mm) diameter;

    g) roll threaded studs, bolts, and screws ≥ 1.5 in. (38.1 mm) diameter;

    h) hot formed nuts < 1.5 in. (38.1 mm) nominal diameter;

    i) hot formed nuts ≥ 1.5 in. (38.1 mm) nominal diameter.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/881ee82d-3251-4bfb-ba37-3ff817ec70e8.htm 01-Feb-17
    API SPEC 20E 2ND ED (A1) Alloy and Carbon Steel Bolting for Use in the Petroleum and Natural Gas Industries; Second Edition 1.1 Purpose

    This standard specifies requirements for the qualification, production and documentation of alloy and carbon steel bolting used in the petroleum and natural gas industries.

    1.2 Applicability

    This standard applies when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance. An annex for supplemental requirements that may be invoked by the purchaser is included.

    1.3 Bolting Specification Levels (BSL)

    This standard establishes requirements for three bolting specification levels (BSL). These three BSL designations define different levels of technical, quality and qualification requirements, BSL-1, BSL-2, and BSL-3. The BSLs are numbered in increasing levels of severity in order to reflect increasing technical, quality and qualification criteria.

    1.4 Bolting Types

    This standard covers the following finished product forms, processes, and sizes:

    a) machined studs;

    b) machined bolts, screws and nuts;

    c) cold formed bolts, screws, and nuts (BSL-1 only);

    d) hot formed bolts and screws < 1.5 in. (38.1 mm) nominal diameter;

    e) hot formed bolts and screws ≥ 1.5 in. (38.1 mm) nominal diameter;

    f) roll threaded studs, bolts, and screws < 1.5 in. (38.1 mm) diameter;

    g) roll threaded studs, bolts, and screws ≥ 1.5 in. (38.1 mm) diameter;

    h) hot formed nuts < 1.5 in. (38.1 mm) nominal diameter;

    i) hot formed nuts ≥ 1.5 in. (38.1 mm) nominal diameter.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d3a9dcb1-8e09-4d6a-b6c2-475ec00f4635.htm 01-Feb-17
    API SPEC 20E 2ND ED (A1) (A2) Alloy and Carbon Steel Bolting for Use in the Petroleum and Natural Gas Industries; Second Edition 1.1 Purpose

    This standard specifies requirements for the qualification, production and documentation of alloy and carbon steel bolting used in the petroleum and natural gas industries.

    1.2 Applicability

    This standard applies when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance. An annex for supplemental requirements that may be invoked by the purchaser is included.

    1.3 Bolting Specification Levels (BSL)

    This standard establishes requirements for three bolting specification levels (BSL). These three BSL designations define different levels of technical, quality and qualification requirements, BSL-1, BSL-2, and BSL-3. The BSLs are numbered in increasing levels of severity in order to reflect increasing technical, quality and qualification criteria.

    1.4 Bolting Types

    This standard covers the following finished product forms, processes, and sizes:

    a) machined studs;

    b) machined bolts, screws and nuts;

    c) cold formed bolts, screws, and nuts (BSL-1 only);

    d) hot formed bolts and screws < 1.5 in. (38.1 mm) nominal diameter;

    e) hot formed bolts and screws ≥ 1.5 in. (38.1 mm) nominal diameter;

    f) roll threaded studs, bolts, and screws < 1.5 in. (38.1 mm) diameter;

    g) roll threaded studs, bolts, and screws ≥ 1.5 in. (38.1 mm) diameter;

    h) hot formed nuts < 1.5 in. (38.1 mm) nominal diameter;

    i) hot formed nuts ≥ 1.5 in. (38.1 mm) nominal diameter.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/7a309adf-f98f-4c50-bf51-14030ad34da9.htm 01-Feb-17
    API SPEC 20F 1ST ED (2015) Corrosion Resistant Bolting for Use in the Petroleum and Natural Gas Industries; First Edition 1.1 Purpose

    This specification specifies requirements for the qualification, production and documentation of corrosion resistant bolting used in the petroleum and natural gas industries.

    1.2 Applicability

    This standard applies when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance.

    1.3 Bolting Specification Levels (BSL)

    This specification establishes requirements for two bolting specification levels (BSL). These two BSL designations define different levels of technical, quality and qualification requirements. The levels are designated as BSL-2 and BSL-3. BSL-2 includes requirements in addition to those stated in the ASTM A453 and API 6A718. BSL-3 adds technical, quality and qualification criteria to BSL-2. BSL-2 and BSL-3 are intended to be comparable to BSL-2 and BSL-3 as found in API 20E. BSL-1 is omitted from this standard.

    1.4 Bolting Types

    This specification covers the following product forms, processes, and sizes:

    a) machined studs;

    b) machined bolts, screws and nuts;

    c) cold headed bolts, screws and nuts;

    d) hot formed bolts and screws

    1.5 in. (38.1 mm) nominal diameter;

    e) hot formed bolts and screws ≥1.5 in. (38.1 mm) nominal diameter;

    f) roll threaded studs, bolts, and screws 1.5 in. (38.1 mm) diameter;

    g) roll threaded studs, bolts, and screws ≥1.5 in. (38.1 mm) diameter;

    h) hot formed nuts 1.5 in. (38.1 mm) nominal diameter;

    i) hot formed nuts ≥1.5 in. (38.1 mm) nominal diameter.

    1.5 Application of the API Monogram

    If product is manufactured at a facility licensed by API and it is intended to be supplied bearing the API Monogram, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/6a8a3f56-1faf-4f5b-af95-8996d56a725b.htm 01-Jun-15
    API SPEC 20F 2ND ED (2018) Corrosion-resistant Bolting for Use in the Petroleum and Natural Gas Industries; Second Edition 1.1 Purpose

    This standard specifies requirements for the qualification, production, and documentation of corrosion-resistant bolting used in the petroleum and natural gas industries.

    1.2 Applicability

    This standard applies when referenced by an applicable API equipment standard or otherwise specified as a requirement for compliance.

    1.3 Bolting Specification Levels (BSL)

    This standard establishes requirements for two bolting specification levels (BSL). These two BSL designations define different levels of technical, quality, and qualification requirements: BSL-2 and BSL-3. The BSLs are numbered in increasing levels of requirements in order to reflect increasing technical, quality, and qualification criteria. BSL-2 and BSL-3 are intended to be comparable to BSL-2 and BSL-3, as found in API 20E. BSL-1 is omitted from this standard.

    1.4 Bolting Types for Qualification

    This standard covers the following product forms, processes, and sizes:

    a) machined studs;

    b) machined bolts, screws, and nuts;

    c) cold-formed bolts, screws, and nuts with cut or cold-formed threads;

    d) hot-formed bolts and screws <1.5 in. (38.1 mm) nominal diameter;

    e) hot-formed bolts and screws ≥1.5 in. (38.1 mm) nominal diameter;

    f) roll threaded studs, bolts, and screws <1.5 in. (38.1 mm) diameter;

    g) roll threaded studs, bolts, and screws ≥1.5 in. (38.1 mm) diameter;

    h) hot-formed nuts <1.5 in. (38.1 mm) nominal diameter;

    i) hot-formed nuts ≥1.5 in. (38.1 mm) nominal diameter.

    1.5 Application of the API Monogram

    If the product is manufactured at a facility licensed by API and is intended to be supplied bearing the API Monogram, the requirements of Annex A apply.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a2243627-53bd-4283-a2bf-b370e04b1aa9.htm 01-May-18
    API SPEC 2B 1ST ED (1969) Fabricated Structural Steel Pipe; First Edition 1.1 Coverage

    This Specification covers the fabrication of structural steel pipe formed from plate steel, with longitudinal and circumferential butt-welded seams in sizes 16 in. OD and larger, with wall feet in length, suitable for use in the construction of welded offshore fixed platforms. Pipe fabricated under this specification is intended to be used primarily in piling and main structural members, including tubular truss joints, where internal stiffeners are not required.

    1.2 Policy

    American Petroleum Institute (API) specification are published as an aid to procurement of standardized equipment and materials. These specifications are other than API, and nothing in any API specification is intended to in anyway inhibit the purchase of products from companies not authorized to use the API monogram.

    1.3

    Nothing contained in any API specification is to construed as granting any right, by implication or otherwise, for the manufacture, sale, or use in connection with any method, apparatus, or product covered by letters patent, nor as insuring anyone against liability for infringement of letter patent.

    1.4

    API specification may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained I them. However, the Institute makes no representation, warranty, or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting their use, for any violation of any federal, state, or municipal regulation with which an API specification may conflict, or not the infringement of any patent resulting from the use of an API specification.

    1.5

    The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram conforms to the applicable API specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/fb7b407b-29d8-447b-89fe-428dfcf47d56.htm 01-Nov-69
    API SPEC 2B 2ND ED (1972) Specification for Fabricated Structural Steel Pipe; Second Edition 1.1 Coverage

    This Specification covers the fabrication of structural steel pipe formed from plate steel, with longitudinal and circumferential butt-welded seams in sizes 16 in. OD and larger, with wall feet in length, suitable for use in the construction of welded offshore fixed platforms. Pipe fabricated under this specification is intended to be used primarily in piling and main structural members, including tubular truss joints, where internal stiffeners are not required.

    1.2 Policy

    American Petroleum Institute (API) specification are published as an aid to procurement of standardized equipment and materials. These specifications are other than API, and nothing in any API specification is intended to in anyway inhibit the purchase of products from companies not authorized to use the API monogram.

    1.3

    Nothing contained in any API specification is to construed as granting any right, by implication or otherwise, for the manufacture, sale, or use in connection with any method, apparatus, or product covered by letters patent, nor as insuring anyone against liability for infringement of letter patent.

    1.4

    API specification may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained I them. However, the Institute makes no representation, warranty, or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting their use, for any violation of any federal, state, or municipal regulation with which an API specification may conflict, or not the infringement of any patent resulting from the use of an API specification.

    1.5

    The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram conforms to the applicable API specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/99d7e814-6580-423d-8d30-829f16ff218a.htm 01-Oct-72
    API SPEC 2B 3RD ED (1977) Specification for Fabricated Structural Steel Pipe; Third Edition 1.1 Coverage

    This Specification covers the fabrication of structural steel pipe formed from plate steel, with longitudinal and circumferential butt-welded seams in sizes 16 in. OD and larger, with wall feet in length, suitable for use in the construction of welded offshore fixed platforms. Pipe fabricated under this specification is intended to be used primarily in piling and main structural members, including tubular truss joints, where internal stiffeners are not required.

    1.2 Policy

    American Petroleum Institute (API) specification are published as an aid to procurement of standardized equipment and materials. These specifications are other than API, and nothing in any API specification is intended to in anyway inhibit the purchase of products from companies not authorized to use the API monogram.

    1.3

    Nothing contained in any API specification is to construed as granting any right, by implication or otherwise, for the manufacture, sale, or use in connection with any method, apparatus, or product covered by letters patent, nor as insuring anyone against liability for infringement of letter patent.

    1.4

    API specification may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained I them. However, the Institute makes no representation, warranty, or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting their use, for any violation of any federal, state, or municipal regulation with which an API specification may conflict, or not the infringement of any patent resulting from the use of an API specification.

    1.5

    The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram conforms to the applicable API specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5d48729c-1999-4835-9c4a-2dc79fde5b31.htm 01-Nov-77
    API SPEC 2B 4TH ED (1990) Specification for the Fabrication of Structural Steel Pipe; Fourth Edition 1.1 Coverage

    This specification covers the fabrication of structural steel pipe formed from plate steel, with longitudinal and circumferential butt-welded seams, in sizes 16 in. Outside diameter (OD) and larger, with wall thickness 3/8 in. and greater (up to 40 feet in length) suitable for use in the construction of welded offshore structures. The use of the ERW process or spiral welded pipe is not included in this specification. Pipe Fabricated under this specification is intended to be used primarily in piling and main structural members, including tubular truss connection, where internal stiffeners are not usually required.

    1.2 Maufacturers

    Manufacturers desiring to apply the API Monogram to the products covered by this specification shall demonstrate to the satisfaction of the American Petroleum Institute a program of education, training, experience, and/or examination assuring the manufacturer’s personnel are competent in welding, inspection, nondestructive examination, and testing required or referenced by this specification.

    1.3 Referred DocumentsThe following specifications and standards become a part of and shall be considered concurrently with this specification.

    ASTM A6-88 —General Requirements for Rolled Steel Plates, Shapes, Sheet Piling, and Bars for Structural Use.

    ASTM A 20-89 —General Requirements for Delivery of Steel Plates for Pressure Vessels.

    ASTM A 370-88 —Mechanical Testing of Steel Products.

    ASTM E 23-88 Notch Bar Impact Testing of Metallic Materials.

    A WS D1.1-88— Structural Welding Code — Steel.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/a4478af7-fde8-4735-8a49-760d89f7e8c3.htm 01-Jul-90
    API SPEC 2B 5TH ED (1996) Specification for the Fabrication of Structural Steel Pipe; Fifth Edition 1.1

    This specification covers the fabrication of structural steel pipe formed from plate steel, with longitudinal and circumferential butt-welded seams, in sizes 16 in. Outside diameter (OD) and larger, with wall thickness 3/8 in. and greater (up to 40 feet in length) suitable for use in the construction of welded offshore structures. The use of the ERW process or spiral welded pipe is not included in this specification. Pipe Fabricated under this specification is intended to be used primarily in piling and main structural members, including tubular truss connection, where internal stiffeners are not usually required.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9e154361-d83d-47c1-9cbb-8ecaa082c859.htm 01-May-96
    API SPEC 2B 6TH ED (R 2012) Specification for the Fabrication of Structural Steel Pipe; Sixth Edition; Reaffirmed, January 2012 1.1

    This specification covers the fabrication of structural steel pipe formed from plate steel with longitudinal and circumferential butt-welded seams, typically in sizes 14 in. outside diameter (OD) and larger (40 in. and larger for LWDS) with wall thickness 3/8 in. and greater (up to a nominal 40 ft in length) suitable for use in construction of welded offshore structures. The use of the ERW process or spiral welded pipe is not included in this specification. Pipe fabricated under this specification is intended to be used primarily in piling and main structural members, including tubular truss connections, where internal stiffeners are not usually required.

    1.2

    Manufacturers desiring to apply the API Monogram to the products covered by this specification shall demonstrate to the satisfaction of the American Petroleum Institute a program of education, training, experience, and/or examination assuring the manufacturer's personnel are competent in welding, inspection, nondestructive examination, and testing required or referenced by this specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/d7e686f5-fb84-4c7d-99a0-a67734c2db70.htm 01-Jan-12
    API SPEC 2C 1ST ED (1971) Offshore Cranes; First Edition 1.1 Coverage Coverage This specification provides a uniform method for establishing rated loads based upon allowable unit stresses for load supporting components (as differentiated from power transmitting mechanisms) of pedestal-mounted revolving cranes used offshore on bottom- supported platforms, floating drilling tenders, semi-submersible rigs, and other types pf floating drilling equipment.

    1.2 Structural components covered by this specification are listed below and shown in Fig. 1.1

    a. Crane boom

    b. Boom head sheave assembly

    c. Job and job mast

    d. Floating harness or bridle

    e. Gantry A-frame

    f. Revolving superstructure

    g. All swing circle or roller path components except actual rolling elements

    h. Boom foot pins

    i. Sheave pins

    j. Boom splice bolts or connectors

    k. Foundation bolts or fastenings

    1.3 Policy American Petroleum Institute (API) specifications are published as an aid to procurement of standardized equipment and materials. These specifications are not intended to inhibit purchasers and producers from purchasing or producing products made to specifications other than API, and nothing in any API specification is intended in any way inhibit the purchase of products from companies not authorized to use the API monogram.

    1.4 Nothing contained in any API specification is to be construed as granting any right by implication or otherwise , for any method , apparatus or product covered by letters patent, nor as insuring anyone against liability for infringement of letters patent.

    1.5 API specifications may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them. However, the Institute makes no representation, warranty or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting from their use, for any violation of federal, state or municipal regulation with which an API specification may conflict, or for the infringement of any patent resulting from the use of an API specification.

    1.6 The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears monogram conforms to the applicable API Specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/cd360b69-a846-4211-ab2e-de4a93ba29dd.htm 01-Mar-71
    API SPEC 2C 2ND ED (1972) Specification for Offshore Cranes; Second Edition 1.1 CoverageCoverage This specification provides a uniform method for establishing rated loads based upon allowable unit stresses for load supporting components (as differentiated from power transmitting mechanisms) of pedestal-mounted revolving cranes used offshore on bottom- supported platforms, floating drilling tenders, semi-submersible rigs, and other types pf floating drilling equipment.

    1.2Structural components covered by this specification are listed below and shown in Fig. 1.1

    a. Crane boom

    b. Boom head sheave assembly

    c. Job and job mast

    d. Floating harness or bridle

    e. Gantry A-frame

    f. Revolving superstructure

    g. All swing circle or roller path components except actual rolling elements

    h. Boom foot pins

    i. Sheave pins

    j. Boom splice bolts or connectors

    k. Foundation bolts or fastenings

    1.3Policy American Petroleum Institute (API) specifications are published as an aid to procurement of standardized equipment and materials. These specifications are not intended to inhibit purchasers and producers from purchasing or producing products made to specifications other than API, and nothing in any API specification is intended in any way inhibit the purchase of products from companies not authorized to use the API monogram.

    1.4Nothing contained in any API specification is to be construed as granting any right by implication or otherwise , for any method , apparatus or product covered by letters patent, nor as insuring anyone against liability for infringement of letters patent.

    1.5

    API specifications may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them. However, the Institute makes no representation, warranty or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting from their use, for any violation of federal, state or municipal regulation with which an API specification may conflict, or for the infringement of any patent resulting from the use of an API specification.

    1.6The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears monogram conforms to the applicable API Specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/dd9bf082-19b8-4ba8-8f8a-ed9983fef5c7.htm 01-Feb-72
    API SPEC 2C 3RD ED (1983) Fabricated Structural Steel Pipe; First Edition 1.1 Coverage This specification details the requirements for pedestal mounted revolving cranes used fir the transfer of materials or personnel to or form vessels.

    1.1.1 Included for establishing rated loads based on allowable unit stresses for load supporting components, as differentiated from power transmitting mechanisms. Also included are minimum equipment requirements, minimum acceptable standards for material, design, manufacturing, and testing, and a quality assurance program. Additional detailed requirements are included in the body of the specification. The required Quality Assurance is defined in Appendix A.

    1.1.2 Structural components covered by this specification are listed below and shown in Fig. 1.1

    a. Crane boom

    b. Boom head sheave assembly

    c. Job and job mast

    d. Floating harness or bridle

    e. Gantry A-frame

    f. Revolving superstructure

    g. All swing circle or roller path components except actual rolling elements

    h. Boom foot pins

    i. Sheave pins

    j. Boom splice bolts or connectors

    k. Foundation bolts or fastenings

    1.1.3 Policy American Petroleum Institute (API) specification are published as an aid to procurement of standardized equipment and materials.

    a)Policy American Petroleum Institute (API) specifications are published as an aid to procurement of standardized equipment and materials. These specifications are not intended to inhibit purchasers and producers from purchasing or producing products made to specifications other than API, and nothing in any API specification is intended in any way inhibit the purchase of products from companies not authorized to use the API monogram.

    b)Nothing contained in any API specification is to be construed as granting any right by implication or otherwise , for any method , apparatus or product covered by letters patent, nor as insuring anyone against liability for infringement of letters patent.

    c)API specifications may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them. However, the Institute makes no representation, warranty or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting from their use, for any violation of federal, state or municipal regulation with which an API specification may conflict, or for the infringement of any patent resulting from the use of an API specification.

    d) The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears monogram conforms to the applicable API Specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/0642d260-f0ac-4176-9bce-8e6efb5661c0.htm 01-Mar-83
    API SPEC 2C 4TH ED (1988) Specifaction for Offshore Cranes; Fourth Edition 1.1 Coverage This specification details the requirements for design, construction, and testing of pedestal mounted elevating and rotating lift devices of the types of illustrated in Figure 1.1 for transfer to materials or personnel to or from marine vessels and structures. This specification is not intended to be employed for the design, fabrication and testing of davits, and or/ emergency escape devices.

    1.1.1 Included are methods for establishing rated loads based on allowable unit stresses for load supporting components, as differentiated from popper transmitting mechanisms. Also included are minimum requirements for equipment, materials, manufacturing procedures, and testing. Additional detailed requirements are included in the body of the specification.

    1.1.2 Structural components covered by this specification are listed below, including some shown in Fig.1.1:

    a. Crane boom

    b. Boom head sheave assembly

    c. Job and job mast

    d. Floating harness or bridle

    e. Gantry A-frame

    f. Revolving superstructure

    g. All swing circle or roller path components except actual rolling elements

    h. Boom foot pins

    i. Sheave pins

    j. Boom splice bolts or connectors

    k. Foundation bolts or fastenings

    l.Pedestal or base

    m.King post or Center Post


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/4cca87cc-b8c7-4ddd-8974-dd229406a4b8.htm 01-Mar-88
    API SPEC 2C 5TH ED (1995) Specification for Offshore Cranes; Fifth Edition This specification details the requirements for design, construction, and testing of pedestal mounted elevating and rotating lift devices of the types of illustrated in Figure 1 for transfer to materials or personnel to or from marine vessels and structures. This specification is not intended to be employed for the design, fabrication and testing of davits, and or/ emergency escape devices.

    1.1.1 Included are methods for establishing rated loads based on allowable unit stresses for load supporting components, as differentiated from popper transmitting mechanisms. Also included are minimum requirements for equipment, materials, manufacturing procedures, and testing. Additional detailed requirements are included in the body of the specification.

    1.1.2 Structural components covered by this specification are listed below, including some shown in Fig.1:

    a. Crane boom

    b. Boom head sheave assembly

    c. Job and job mast

    d. Floating harness or bridle

    e. Gantry A-frame

    f. Revolving superstructure

    g. All swing circle or roller path components except actual rolling elements

    h. Boom foot pins

    i. Sheave pins

    j. Boom splice bolts or connectors

    k. Foundation bolts or fastenings

    l.Pedestal or base

    m.King post or Center Post

    Record RetentionThe manufacturer shall maintain all inspection and testing of records for 20 years. These records shall be employed in a quality audit program of assesing or eliminating design, manufacturing, or inspection functions which may have been contributed to the malfunction or failure.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/33bb825c-97a7-4e3b-8ed3-0101e0c21071.htm 01-Apr-95
    API SPEC 2C 6TH ED (2004) Specification for Offshore Pedestal Mounted Cranes; Sixth Edition; Effective Date March 2004 1.1 General This specification details the requirements for design, construction,

    and testing of offshore pedestal mounted cranes. Offshore cranes are defined herein as pedestal mounted elevating and rotating lift devices of the types illustrated in Figure 1 for transfer of materials or personnel to or from marine vessels and structures. Offshore cranes are typically mounted on a fixed (bottom supported) or floating platform structure used in drilling and production operations. API Spec 2C is not intended to be used for the design, fabrication, and testing of davits and/or emergency escape devices. API Spec 2C is also not intended to be used for shipboard cranes or heavy lift cranes. Shipboard cranes are mounted on surface type vessels and are used to move cargo, containers, and other materials while the crane is within a harbor or sheltered area. Heavy lift cranes are mounted on barges or other vessels and are used in construction and salvage operations within a harbor or sheltered area or in very mild offshore environmental conditions.

    1.2 Safe Working Limits The intent of this specification is to establish safe working limits for the crane in anticipated operations and conditions. This is accomplished by establishing Safe Working Loads (SWLs) based on allowable unit stresses and design factors. Operation of the crane outside of the limits established by the manufacturer in accordance with the guidelines set forth in this document can result in catastrophic failure up to and including separating the entire crane and operator from the foundation. Compliance with the allowable stresses and design factors set forth in this specification does not guarantee that the crane will not be dismounted from its foundation in the event of a gross overload such as might occur in the event of snagging the supply boat.

    1.3 Critical Components A critical component is any component of the crane assembly devoid of redundancy and/or auxiliary restraining devices whose failure would result in an uncontrolled descent of the load or uncontrolled rotation of the upper-structure. Due to their criticality, these components are required to have stringent design, material, traceability, and inspection requirements. The manufacturer shall prepare a list of all critical components for each crane. Appendix A contains an example list of critical components.

    1.4 Commentary Further information and references on various topics contained in this specification are included in the Commentary found in Appendix B. The section numbers in Appendix B correspond to the section numbers of this specification. For example, Section 4.3 of this specification, entitled In-service Loads, corresponds to Section B.4.3 in Appendix B.

    1.5 RECORD RETENTION The manufacturer shall maintain all inspection and testing records for 20 years. These records shall be employed in a quality audit program of assessing malfunctions and failures for the purpose of correcting or eliminating design, manufacturing, or inspection functions, which may have contributed to the malfunction or failure.

    1.6 Manufacturer Supplied Documentation The manufacturer shall supply to the purchaser certain documentation for each crane manufactured. Unless otherwise agreed to by the purchaser, the documentation shall include:

    1. Load and information charts oer section 4.2.

    2. Crane foundation design forces and moments per section 5.2

    3. List of all critical components per Section 1.3 and certification that these components meet the API Spec 2C material, traceability, welding (as applicable), and nondestructive examination requirements.

    Operations, Parts, and Maintenance Manual.

    5. If requested by the purchaser, failure mode assessments for gross un-intended overloads as per Section 4.6.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/067ade0c-603f-4f0c-b476-095e565dcf5c.htm 01-Mar-04
    API SPEC 2C 7TH ED (E1) Offshore Pedestal-mounted Cranes; Seventh Edition; Effective Date: October 1, 2012 This specification provides requirements for design, construction, and testing of new offshore pedestal-mounted cranes. For the purposes of this specification, offshore cranes are defined as pedestal-mounted elevating and rotating lift devices for transfer of materials or personnel to or from marine vessels, barges and structures.

    Typical applications can include:

    a) offshore oil exploration and production applications; these cranes are typically mounted on a fixed (bottomsupported) structure, floating platform structure, or ship-hulled vessel used in drilling and production operations;

    b) shipboard applications; these cranes are mounted on surface-type vessels and are used to move cargo, containers, and other materials while the crane is within a harbor or sheltered area; and

    c) heavy-lift applications; cranes for heavy-lift applications are mounted on barges, self-elevating vessels or other vessels, and are used in construction and salvage operations within a harbor or sheltered area or in limited (mild) environmental conditions.

    Figure 1 illustrates some (but not all) of the types of cranes covered under this specification. While there are many configurations of pedestal-mounted cranes covered in the scope of this specification, it is not intended to be used for the design, fabrication, and testing of davits or emergency escape devices. Additionally, this specification does not cover the use of cranes for subsea lifting and lowering operations or constant-tension systems.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/212a47be-0109-4172-8b0a-990ef6e427b4.htm 01-Mar-13
    API SPEC 2F 6TH ED (R 2015) Specification for Mooring Chain; Sixth Edition; Reaffirmed, June 2015 This specification covers flash-welded chain and forged kenter connecting links used for mooring of offshore floating vessels such as drilling vessels, pipe lay barges, derrick barges, and storage tankers.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/f8654d16-9f15-4bd2-b54c-6f3c47fc3e21.htm 01-Jun-15
    API SPEC 2H 2ND ED (1979) Specification for Carbon Magnese Steel Plate for Offshore Platform Tubular Joints; Second Edition 1.1 Coverage This specification covers intermediate strength steel up to 3 in, thick for use in welded tubular construction of offshore platforms, in selected critical portions which must resist impact, plastic fatigue fading , lamellar tearing. This material is intended for fabrication primarily by cold forming and welding as per API Spec 2B. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steel and the intended service. Conversely, the steel should be amenable to fabrication and welding under shipyard and offshore conditions.

    1.2 The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminators and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for rejection. If supplementary Requirement S-1 is not used, it is recommended that the plates be subjected to ultrasonic inspection in the fabrication yard prior to being formed into tubular members. Areas of lamination can be determined and marked to permit the placing of these areas where there will not be subject to thru-thickness loading.

    1.3 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperature climate (14°F minimum service temperature). Cold formed tubulars have less toughness due to straining than that of the original flat plates in section 6 take typical losses in toughens due to straining and aging into consideration. For areas with lower test temperatures shall be used, or fabrication process shall be modified to limit degradation. Supplementary Requirement S-2 provides for impact test at temperatures other than specified in Sect. 6

    1.4 Policy American Petroleum Institute (API) specifications are published as an aid to procurement of standardized equipment and materials . These specification other than API, and nothing in any API specification is intended to in to in any way inhibit the purchase of products from companies not authorized to use the API monogram.

    1.5 Nothing contained in any API specification is to construed as granting any right, implication or otherwise, for the manufacture, sale, or, use in connection with any method, apparatus or product covered by letters patent, nor as insuring anyone against liability for infringement.

    1.6 API specification may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them. However, the Institute makes no representation, warranty or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting from their use, for any violation of any federal, state or municipal regulation with which an API specification may conflict, or for the infringement of any patent resulting from the use an API 1.7 The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears the monogram conforms to the applicable API specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/39858c12-cea5-41ac-a42c-84cfa190454b.htm 01-Mar-79
    API SPEC 2H 3RD ED (1983) Specification for Carbon Manganese Steel Plate for Offshore Platform Tubular Joints; Third Edition 1.1 Coverage This specification covers intermediate strength steel up to 3 in, thick for use in welded tubular construction of offshore platforms, in selected critical portions which must resist impact, plastic fatigue fading , lamellar tearing. This material is intended for fabrication primarily by cold forming and welding as per API Spec 2B. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steel and the intended service. Conversely, the steel should be amenable to fabrication and welding under shipyard and offshore conditions.

    1.2 The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminators and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for rejection. If supplementary Requirement S-1 is not used, it is recommended that the plates be subjected to ultrasonic inspection in the fabrication yard prior to being formed into tubular members. Areas of lamination can be determined and marked to permit the placing of these areas where there will not be subject to thru-thickness loading.

    1.3 For applications where through-thickness properties are important but not of sufficient concern to justify the expense of Z direction testing, supplementary requirement S-5 provides a low sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement s-5 is neither a substitute for S-4 Through Thickness Testing nor a guarantee of a minimum level of through-thickness ductility.Experience indicates, however, that low-sulfur carbon manganese steels, when tested, usually exhibit percent reduction-of-area of atlas 20. Accordingly , supplementary requirement S-4 when testing is not desired. If tested, low sulfur steel is desired, then both supplementary requirement S-4 and S-5 should be ordered

    1.4 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperature climate (14°F minimum service temperature). Cold formed tubulars have less toughness due to straining than that of the original flat plates in section 6 take typical losses in toughens due to straining and aging into consideration. For areas with lower test temperatures shall be used, or fabrication process shall be modified to limit degradation. Supplementary Requirement S-2 provides for impact test at temperatures other than specified in Sect. 6

    1.5 Policy American Petroleum Institute (API) specifications are published as an aid to procurement of standardized equipment and materials . These specification other than API, and nothing in any API specification is intended to in to in any way inhibit the purchase of products from companies not authorized to use the API monogram.

    1.6 Nothing contained in any API specification is to construed as granting any right, implication or otherwise, for the manufacture, sale, or, use in connection with any method, apparatus or product covered by letters patent, nor as insuring anyone against liability for infringement.

    1.7 API specification may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them. However, the Institute makes no representation, warranty or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting from their use, for any violation of any federal, state or municipal regulation with which an API specification may conflict, or for the infringement of any patent resulting from the use an API 1.8 The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears the monogram conforms to the applicable API specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/4b12e471-9a7e-47b2-a196-1fe327d7beb8.htm 01-Mar-83
    API SPEC 2H 4TH ED (1986) Specification for Carbon Manganese Steel Plate for Offshore Platfotm Tubular Joints; Fourth Edition 1.1 Coverage This specification covers intermediate strength steel up to 3 in, thick for use in welded tubular construction of offshore platforms, in selected critical portions which must resist impact, plastic fatigue fading , lamellar tearing. This material is intended for fabrication primarily by cold forming and welding as per API Spec 2B. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steel and the intended service. Conversely, the steel should be amenable to fabrication and welding under shipyard and offshore conditions.

    1.2 The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminators and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for rejection. If supplementary Requirement S-1 is not used, it is recommended that the plates be subjected to ultrasonic inspection in the fabrication yard prior to being formed into tubular members. Areas of lamination can be determined and marked to permit the placing of these areas where there will not be subject to thru-thickness loading.

    1.3 For applications where through-thickness properties are important but not of sufficient concern to justify the expense of Z direction testing, supplementary requirement S-5 provides a low sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement s-5 is neither a substitute for S-4 Through Thickness Testing nor a guarantee of a minimum level of through-thickness ductility.Experience indicates, however, that low-sulfur carbon manganese steels, when tested, usually exhibit percent reduction-of-area of atlas 20. Accordingly , supplementary requirement S-4 when testing is not desired. If tested, low sulfur steel is desired, then both supplementary requirement S-4 and S-5 should be ordered

    1.4 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperature climate (14°F minimum service temperature). Cold formed tubulars have less toughness due to straining than that of the original flat plates in section 6 take typical losses in toughens due to straining and aging into consideration. For areas with lower test temperatures shall be used, or fabrication process shall be modified to limit degradation. Supplementary Requirement S-2 provides for impact test at temperatures other than specified in Sect. 6

    1.5 Policy American Petroleum Institute (API) specifications are published as an aid to procurement of standardized equipment and materials . These specification other than API, and nothing in any API specification is intended to in to in any way inhibit the purchase of products from companies not authorized to use the API monogram.

    1.6 Nothing contained in any API specification is to construed as granting any right, implication or otherwise, for the manufacture, sale, or, use in connection with any method, apparatus or product covered by letters patent, nor as insuring anyone against liability for infringement.

    1.7 API specification may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them. However, the Institute makes no representation, warranty or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting from their use, for any violation of any federal, state or municipal regulation with which an API specification may conflict, or for the infringement of any patent resulting from the use an API 1.8 The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears the monogram conforms to the applicable API specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9d8ad981-7400-4d04-b3d7-526727173f1b.htm 01-Apr-86
    API SPEC 2H 5TH ED (1988) Specification for Carbon Manganese Steel Plate for Offshore Platform Tubular Joints; Fifth Edition 1.1 Coverage This specification covers two grades of intermediate strength steel plates up to 4 in. thick for use in welded tubular construction of offshore platforms, in selected critical portions which must resist impact, plastic fatigue loading, and lamellar tearing. This material is intended for fabrication primarily by cold forming and welding as per API Spec 2B. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steel and the intended service. Conversely, the steel should be amenable to fabrication and welding under shipyard and offshore conditions. API Specification 2W and 2Y cover companion steels providing similar mechanical properties but with improved weldability. This improvement results from a reduction in the maximum allowed chemical composition and is made possible by changes in the method of heat and/ or processing.

    1.2 The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminators and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptation. If if the purchaser chooses not to specify Supplementary Requirement S-1 it is recommended that a fabrication yard ultrasonic examination be preformed, prior to fit up, to permit relocation of undesirable laminar imperfections to areas free from through-thickness loadings.

    1.3 For applications where through-thickness properties are important but not of sufficient concern to justify the expense of Z direction testing, supplementary requirement S-5 provides a low sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement s-5 is neither a substitute for S-4 Through Thickness Testing nor a guarantee of a minimum level of through-thickness ductility.Experience indicates, however, that low-sulfur carbon manganese steels, when tested, usually exhibit percent reduction-of-area of at least 20% reduction of area. Accordingly , supplementary requirement S-5 when testing is not desired. If tested, low sulfur steel is desired, then both supplementary requirement S-4 and S-5 should be ordered.

    1.4 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperature climate (14°F minimum service temperature). Cold formed materials have less toughness due to straining and aging however, differenced in composition or fabrication practices may result in significantly greater degradation than that just included. Supplementary Requirements S-7 and/ or S-8 deal with strain-aging problem, and consideration should be given to invoking S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % stain) exceeds 0.040. Supplementary Requirement S-8 provides for testing at the specific temperatures and strain levels of interest and is recommended for all martial purchases which exceed the purchaser’s experience base.

    1.4.1For applications with lower service temperatures, lower test temperatures should be considered Supplementary Requirement S-2 provides for impact tests at temperatures other than those specified in Section 6. S2.1 provides for NDTT or Charpy V-notch testing at -60°c. S2.2 provides for such testing at temperatures less than -40° C but other than -60°C.

    1.5 The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears the monogram conforms to the applicable API specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/9dd49b9a-2579-4ac8-b016-c668d5b69abf.htm 01-Jul-88
    API SPEC 2H 6TH ED (1990) Specification for Carbon Manganese Steel Plate for Offshore Platform Tubular Joints; Sixth Edition 1.1 Coverage This specification covers two grades of intermediate strength steel plates up to 4 in. thick for use in welded tubular construction of offshore platforms, in selected critical portions which must resist impact, plastic fatigue loading, and lamellar tearing. This material is intended for fabrication primarily by cold forming and welding as per API Spec 2B. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steel and the intended service. Conversely, the steel should be amenable to fabrication and welding under shipyard and offshore conditions. API Specification 2W and 2Y cover companion steels providing similar mechanical properties but with improved weldability. This improvement results from a reduction in the maximum allowed chemical composition and is made possible by changes in the method of heat and/ or processing.

    1.2 The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminators and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptance.

    1.3 For applications where through-thickness properties are important but not of sufficient concern to justify the expense of Z direction testing, supplementary requirement S-5 provides a low sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S-5 is neither a substitute for S-4 Through Thickness Testing nor a guarantee of a minimum level of through-thickness ductility.Experience indicates, however, that low-sulfur carbon manganese steels, when tested, usually exhibit percent reduction-of-area of at least 20% reduction of area. Accordingly , supplementary requirement S-4 when testing is not desired. If tested, low sulfur steel is desired, then both supplementary requirement S-4 and S-5 should be ordered.

    1.4 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperature climate (14°F minimum service temperature). Cold formed materials have less toughness due to straining and aging however, differenced in composition or fabrication practices may result in significantly greater degradation than that just included. Supplementary Requirements S-7 and/ or S-8 deal with strain-aging problem, and consideration should be given to invoking S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % stain) exceeds 0.040. Supplementary Requirement S-8 provides for testing at the specific temperatures and strain levels of interest and is recommended for all martial purchases which exceed the purchaser’s experience base.

    1.4.1 For applications with lower service temperatures, lower test temperatures should be considered Supplementary Requirement S-2 provides for impact tests at temperatures other than those specified in Section 6. S2.1 provides for NDTT or Charpy V-notch testing at -60°c. S2.2 provides for such testing at temperatures less than -40° C but other than -60°C.

    1.5 The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears the monogram conforms to the applicable API specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/576de2ed-63ca-47f7-b2ef-c07737b34bed.htm 01-Jul-90
    API SPEC 2H 7TH ED (1993) Specification for Carbon Manganese Steel Plate for Offshore Platform Tubular Joints; Seventh Edition 1.1 Coverage This specification covers two grades of intermediate strength steel plates up to 4 in. thick for use in welded tubular construction of offshore platforms, in selected critical portions which must resist impact, plastic fatigue loading, and lamellar tearing. This material is intended for fabrication primarily by cold forming and welding as per API Spec 2B. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steel and the intended service. Conversely, the steel should be amenable to fabrication and welding under shipyard and offshore conditions. API Specification 2W and 2Y cover companion steels providing similar mechanical properties but with improved weldability. This improvement results from a reduction in the maximum allowed chemical composition and is made possible by changes in the method of heat and/ or processing.

    1.2 The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminators and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptance.

    1.3 For applications where through-thickness properties are important but not of sufficient concern to justify the expense of Z direction testing, supplementary requirement S-5 provides a low sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S-5 is neither a substitute for S-4 Through Thickness Testing nor a guarantee of a minimum level of through-thickness ductility.Experience indicates, however, that low-sulfur carbon manganese steels, when tested, usually exhibit percent reduction-of-area of at least 20% reduction of area. Accordingly , supplementary requirement S-4 when testing is not desired. If tested, low sulfur steel is desired, then both supplementary requirement S-4 and S-5 should be ordered.

    1.4 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperature climate (14°F minimum service temperature). Cold formed materials have less toughness due to straining and aging however, differenced in composition or fabrication practices may result in significantly greater degradation than that just included. Supplementary Requirements S-7 and/ or S-8 deal with strain-aging problem, and consideration should be given to invoking S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % stain) exceeds 0.040. Supplementary Requirement S-8 provides for testing at the specific temperatures and strain levels of interest and is recommended for all martial purchases which exceed the purchaser’s experience base.

    1.4.1 For applications with lower service temperatures, lower test temperatures should be considered Supplementary Requirement S-2 provides for impact tests at temperatures other than those specified in Section 6. S2.1 provides for NDTT or Charpy V-notch testing at -60°c. S2.2 provides for such testing at temperatures less than -40° C but other than -60°C.

    1.5 The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears the monogram conforms to the applicable API specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/8076c532-322c-4f6d-8da9-879bf3ad581b.htm 01-Jul-93
    API SPEC 2H 8TH ED (1999) Specification for Carbon Manganese Steel Plate for Offshore Platform Tubular Joints; Eighth Edition 1.1 This specification covers two grades of intermediate strength steel plates up to 4 in. thick for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, and lamellar tearing. These steels are intended for fabrication primarily by cold forming and welding as per API Spec 2B. The welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Conversely, the steels should be amenable to fabrication and welding under shipyard and offshore conditions. API Specifications 2W and 2Y cover companion steels providing similar mechanical properties but with improved weldability. This improvement results from a reduction in the maximum allowed chemical composition and is made possible by changes in the method of heat treatment and/or processing.

    1.2 The primary use of these steels is in tubular joints, stiffened plate construction, and other intersections where portions of the plates will be subjected to tension in the thickness direction (Z direction). Supplementary Requirement S-4 provides for through-thickness (Z direction) testing of the plates by the material manufacturer and specified limits for acceptance. Supplementary Requirement S-1 provides for ultrasonic examination of the plates by the material manufacturer and specifies limits for acceptance.

    1.3 For applications where through-thickness properties are important but Z direction testing has not been specified, Supplementary Requirement S-5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplementary requirement S-5 is neither a substitute for S-4 Through Thickness Testing nor a guarantee of a minimum level of through-thickness ductility. Experience indicates, however, that tests of low-sulfur carbon-manganese steels usually show at least 20% reduction-of-area. Accordingly, supplementary requirement S-5 is intended as an alternative to supplementary requirement S-4 when testing is not desired. If tested, low-sulfur steel is desired, then both supplementary requirements S-4 and S-5 should be ordered.

    1.4 The notch toughness requirements specified in Section 7 or S-12 are suitable for application below water or above water in areas of temperate climate (14°F minimum service temperature). Cold-formed materials have less toughness due to straining than that of the original flat plate, especially in those areas aged by the attachment welding of stubs or braces. The requirements for plates in Section 7 include a moderate adjustment for losses in toughness due to straining and aging; however, differences in composition or fabrication practices may result in significantly greater degradation than that included. Supplementary Requirements S-7 and S-8 deal with the strainaging problem, and consideration should be given to invoking S-7 and/or S-8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040. Supplementary Requirement S-8 provides for testing at the specific temperatures and strain levels of interest and is recommended for all material purchases which exceed the purchaser’s experience base.

    1.4.1 For applications with lower service temperatures, lower test temperatures should be considered. Supplementary Requirement S-2 provides for impact tests at temperatures other than those specified in Section 6 or S-12. S2.1 provides for Drop Weight or Charpy V-notch testing at – 60°C. S2.2 provides for such testing at temperatures less than – 40°C but other than – 60°C.

    1.5 Manufacturers desiring to apply the API Monogram to products covered by this specification shall demonstrate to the satisfaction of the American Petroleum Institute a program of education, training, experience, and/or examination assuring the manufacturer’s personnel are competent in chemical analysis, inspection, testing, and nondestructive examinations required or referenced by this specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/da2e0c77-1966-4ac6-b5ab-faee20234742.htm 01-Aug-99
    API SPEC 2H 9TH ED (2007) Specification for Magnese Steel Plate for Offshore Stuctures; Ninth Edition; Effective date: January 2007 1.1 This specification covers two grades of intermediate strength steel plates up to 4 in. thick for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, and lamellar tearing. These

    steels are intended for fabrication primarily by cold forming and welding as per API Spec 2B. The welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Conversely, the steels should be amenable to fabrication and welding under shipyard and offshore conditions. API Specifications 2W and 2Y cover companion steels providing similar mechanical properties but with the advantage of potentially lower preheats, and the availability of API RP 2Z prequalification of HAZ toughness. This improvement results from a reduction in the maximum allowed chemical composition and is made possible by changes in the method of heat treatment and/or processing.

    1.2 The primary use of these steels is in tubular joints, stiffened plate construction, and other intersections where portions of the plates will be subjected to tension in the thickness direction (Z-direction). Supplementary Requirement S4 provides for throughthickness (Z-direction) testing of the plates by the material manufacturer and specified limits for acceptance. Supplementary Requirement S1 provides for ultrasonic examination of the plates by the material manufacturer and specifies limits for acceptance. For applications where through-thickness properties are desirable but the expense of extra testing is not considered necessary, Supplementary Requirement S5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplementary requirement S5 is neither a substitute for S4 Through-Thickness Testing nor a guarantee of a minimum level of through-thickness ductility. Experience indicates, however, that tests of low-sulfur carbon-manganese steels would usually show at least 20% reduction-of-area in a Z-direction tension test. Even without S5, API Spec 2H provides a reduced sulfur level, compared to other common structural steels.

    1.3 The notch toughness requirements specified in Section 7 or S12 are suitable for application below water or above water in areas of temperate climate [14°F (–10°C) minimum service temperature]. Cold-formed materials have less toughness due to straining than that of the original flat plate, especially in those areas aged by the attachment welding of stubs or braces. The requirements for plates in Section 7 include a moderate adjustment for losses in toughness due to straining and aging; however, differences in composition or fabrication practices may result in significantly greater degradation than that included. Supplementary Requirements S7 and S8 deal with the strain-aging problem, and consideration should be given to invoking S7 and/or S8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040. Supplementary Requirement S8 provides for testing at the specific temperatures and strain levels of interest and is recommended for all material purchases which exceed the purchaser’s experience base. For applications with lower service temperatures, lower test temperatures should be considered. Supplementary Requirement S2 provides for impact tests at temperatures other than those specified in Section 6 or S12. S2.1 provides for Drop Weight or Charpy V-notch testing at –76°F (–60°C). S2.2 provides for such testing at temperatures less than –40°F (–40°C) but other than –76°F (–60°C).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/f9f0e42b-0918-40e4-b9cd-63783fb4c388.htm 01-Jan-07
    API SPEC 2H 9TH ED (R 2012) Specification for Carbon Manganese Steel Plate for Offshore Structures; Ninth Edition; Effective Date: February 1, 2007; Reaffirmed, January 2012 1.1

    This specification covers two grades of intermediate strength steel plates up to 4 in. thick for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, and lamellar tearing. These steels are intended for fabrication primarily by cold forming and welding as per API Spec 2B. The welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Conversely, the steels should be amenable to fabrication and welding under shipyard and offshore conditions. API Specifications 2W and 2Y cover companion steels providing similar mechanical properties but with the advantage of potentially lower preheats, and the availability of API RP 2Z prequalification of HAZ toughness. This improvement results from a reduction in the maximum allowed chemical composition and is made possible by changes in the method of heat treatment and/or processing.

    1.2

    The primary use of these steels is in tubular joints, stiffened plate construction, and other intersections where portions of the plates will be subjected to tension in the thickness direction (Z-direction). Supplementary Requirement S4 provides for through thickness (Z-direction) testing of the plates by the material manufacturer and specified limits for acceptance. Supplementary Requirement S1 provides for ultrasonic examination of the plates by the material manufacturer and specifies limits for acceptance. For applications where through-thickness properties are desirable but the expense of extra testing is not considered necessary, Supplementary Requirement S5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplementary requirement S5 is neither a substitute for S4 Through-Thickness Testing nor a guarantee of a minimum level of through-thickness ductility. Experience indicates, however, that tests of low-sulfur carbon-manganese steels would usually show at least 20% reduction-of-area in a Z-direction tension test. Even without S5, API Spec 2H provides a reduced sulfur level, compared to other common structural steels.

    1.3

    The notch toughness requirements specified in Section 7 or S12 are suitable for application below water or above water in areas of temperate climate [14°F (–10°C) minimum service temperature]. Cold-formed materials have less toughness due to straining than that of the original flat plate, especially in those areas aged by the attachment welding of stubs or braces. The requirements for plates in Section 7 include a moderate adjustment for losses in toughness due to straining and aging; however, differences in composition or fabrication practices may result in significantly greater degradation than that included. Supplementary Requirements S7 and S8 deal with the strain-aging problem, and consideration should be given to invoking S7 and/or S8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040. Supplementary Requirement S8 provides for testing at the specific temperatures and strain levels of interest and is recommended for all material purchases which exceed the purchaser's experience base.

    For applications with lower service temperatures, lower test temperatures should be considered. Supplementary Requirement S2 provides for impact tests at temperatures other than those specified in Section 6 or S12. S2.1 provides for Drop Weight or Charpy V-notch testing at –76°F (–60°C). S2.2 provides for such testing at temperatures less than –40°F (–40°C) but other than –76°F (–60°C).


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/3ce3fc21-5f25-47f0-82b7-216f60bdd8f5.htm 01-Jan-12
    API SPEC 2MT1 1ST ED (1994) Specification for As-Rolled Carbon Manganese Steel Plate with Improved Toughness for Offshore Structures; First Edition 1.1 Coverage

    This specification covers one grade of intermediate strength steel planes, through 2 1/2 inches thick, for use in welded construction of offshore structures. These steels are intended for fabrication primarily by cold forming and welding as per API Spec 2B. The welding procedure is of fundamental importance, and it is presumed that procedures will be suitable for the steels and their intended service. Conversely, the steel should be amenable to fabrication and welding under shipyard and offshore conditions. These steels are suitable for use in selected portions of offshoe structures which must resist impact and plastic fatigue loading.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/108d7bd3-e033-47e7-956c-eed3858cd65e.htm 01-Nov-94
    API SPEC 2MT1 2ND ED (R 2012) Specification for Carbon Manganese Steel Plate with Improved Toughness for Offshore Structures; Second Edition; Effective Date: March 1, 2002; Reaffirmed, January 2012 1.1 COVERAGE

    This specification covers one grade of intermediate strength steel plates, though 2(1/2)in. thick, for use in welded construction of offshore structures. These steels are intended for fabrication primarily by cold forming and welding as per API Spec 2B. The welding procedure is of fundamental importance, and it is presumed that procedures will be suitable for the steels and their intended service. Conversely, the steel should be amendable to fabrication and welding under shipyard and offshore conditions. These steels are suitable for use in selected portions of offshore structures, which must resist impact and plastic fatigue loading. When hot or warm forming or PWHT above 1100¡F is anticipated for accelerated cooling (AC) or quenched and tempered (QC) plates, S9 should be invoked, (italics added per ASTM A913).

    1.2 PRIMARY APPLICATION

    The primary use of these steels is for Class "OBO" applications as defined in API RP 2A. API Specs 2H, 2W, and 2Y cover other steels providing improved mechanical properties and toughness for Class ÒAÓ applications and should be used where substantial z-direction stresses are expected.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/7f316a59-5f2f-4157-a687-9c50d74e55e7.htm 01-Jan-12
    API SPEC 2MT2 1ST ED (A1) Rolled Shaped with Improved Notch Toughness; First Edition; Effective Date: December 1, 2002; Reaffirmed, June 2015 1 Scope

    1.1 This specification covers rolled shapes (wide flange shapes, angles, etc.), having a specified minimum yield strength of 50 ksi (345 Mpa), intended for use in offshore structures. Commonly available Class A, Class B, and Class C beams refer to degrees of fracture criticality as described in section 8.1.3 of API RP 2A, with Class C being for the least critical applications. For special critical applications, Class AAZ shapes may be specified, by agreement, using supple- ment S101.

    1.2 Supplementary requirements are provided for use where additional testing or additional restrictions are required by the purchaser. Such requirements apply only when speci- fied in the purchase order.

    1.3 When the steel is to be welded, a welding procedure suitable for the grade of steel and intended use or service is to be utilized. For the purposes of welding procedure qualifica- tion under AWS D1.1, until AWS cites this specification, use the following:

    1.4 When heat straightening, hot or warm forming, or post- weld heat treatment above 1050°F (565°C) is anticipated for Class A shapes produced by methods other than hot rolling, controlled rolling, normalized rolling, or normalizing, supple- ment S9 should be invoked.

    1.5 By agreement, this specification may be used as a sup- plement to purchase rolled shapes to other international stan- dards, e.g., Euronorm, ISO, or JIS, in which case references to ASTM A6 may be replaced by the comparable interna- tional standard. Users should note that dimensions and design properties might not be the same as A6 shape designations, and that “equivalent” sections could be heavier.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/5b63f7e6-43d7-4627-9da2-e8bcee9a1f6a.htm 01-Jun-15
    API SPEC 2MT2 1ST ED (R 2015) Rolled Shaped with Improved Notch Toughness; First Edition; Effective Date: December 1, 2002; Reaffirmed, June 2015 1.1

    This specification covers rolled shapes (wide flange shapes, angles, etc.), having a specified minimum yield strength of 50 ksi (345 Mpa), intended for use in offshore structures. Commonly available Class A, Class B, and Class C beams refer to degrees of fracture criticality as described in section 8.1.3 of API RP 2A, with Class C being for the least critical applications. For special critical applications, Class AAZ shapes may be specified, by agreement, using supplement S101.

    1.2

    Supplementary requirements are provided for use where additional testing or additional restrictions are required by the purchaser. Such requirements apply only when specified in the purchase order.

    1.3

    When the steel is to be welded, a welding procedure suitable for the grade of steel and intended use or service is to be utilized. For the purposes of welding procedure qualification under AWS D1.1, until AWS cites this specification, use the following:

    a. Matching filler metals (AWS D1.1, Table 3.1) shall be as for Group II.

    b. Preheats (AWS D1.1, Table 3.2) shall be as for Category B (or Category D for class A-QST herein).

    c. Matching weld toughness (AWS D1.1, Tables C4.2 and C4.3) shall correspond to Class A, B, or C herein.

    Alternative preheats (AWS D1.1, Annex XI) may also be used to advantage.

    1.4

    When heat straightening, hot or warm forming, or postweld heat treatment above 1050°F (565°C) is anticipated for Class A shapes produced by methods other than hot rolling, controlled rolling, normalized rolling, or normalizing, supplement S9 should be invoked.

    1.5

    By agreement, this specification may be used as a supplement to purchase rolled shapes to other international standards, e.g., Euronorm, ISO, or JIS, in which case references to ASTM A6 may be replaced by the comparable international standard. Users should note that dimensions and design properties might not be the same as A6 shape designations, and that "equivalent" sections could be heavier.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/9ed659b6-c997-4f67-b8e5-b262936fc6bb.htm 01-Jun-15
    API SPEC 2SC 1ST ED (R 2015) Manufacture of Structural Steel Castings for Primary Offshore Applications; First Edition; Effective Date: March 1, 2010; Reaffirmed, June 2015 Castings manufactured to this specification are intended for use in the fabrication of offshore structures, manufacture of critical marine or mechanical or other system components intended for application on permanent offshore structures, or for components used in the construction of offshore tendons, risers and pipelines.

    If national and/or local regulations exist in which some of the requirements may be more stringent than in this specification the contractor shall determine which of the requirements are more stringent and which combination of requirements will be acceptable with respect to safety, environmental, economic, and legal aspects. In all cases, the contractor shall inform the purchaser of any deviation from the requirements of this specification which is considered to be necessary in order to comply with national and/or local regulations.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/59746c42-1b49-42f0-a413-8dd35b7f12fc.htm 01-Jun-15
    API SPEC 2SF 1ST ED (2013) Manufacture of Structural Steel Forgings for Primary Offshore Applications; First Edition Forgings manufactured to this specification are intended for use in the fabrication of offshore structures, marine risers, TLP tendons and pipelines, or other system components intended for application on permanent offshore structures. This specification defines the minimum requirements for manufacture, testing, and inspection of carbon and low-alloy steel forgings, including extrusions and heavy-wall seamless tubular product, grades 345 N/mm2 to 586 N/mm2 (50 ksi to 85 ksi) for use in primary steel applications.

    Service categories A, B, and C (SCA, SCB, and SCC) reflect forging geometry and method of incorporation into the overall system, rather than levels of criticality. They may also be designated by the user (purchaser) as described in 4.4 to reflect moderately different but standardized levels of performance.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/33fe77df-2785-4c02-802b-940d34ceccc0.htm 01-Aug-13
    API SPEC 2W 1ST ED (1987) Specification for Steel Plates for Offshore Structures; Thermo-Mechanical Control Processing (TMCP); First Edition 1.1 Coverage

    This specification covers four grades of intermediate strength steel plates for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, lamellar tearing. Grades 42, 50, and 50Tare covered in thicknesses up to 6 in. [150 mm] inclusive, and Grade 60 is covered in thicknesses up to 4 in. [100 mm] inclusive.

    1.1.1

    It is intended that steel produced to Grades 42 and 50T of the basic API Spec 2W, without Supplementary Requirements, although produced in a different manner and of somewhat different chemical compositions, be at least equivalent in minimum performance and, therefore, in service application, to the corresponding grades listed in API Spec 2H. Higher performance (Ie., notch toughness at lower temperatures, or enhanced weldability) typically available with TMCP steel may be achieved by specification of Supplementary Requirements.

    1.1.2

    These steels are intended for fabrication primarily by cold forming and welding. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Because of the characteristic high YS/TS ratio of TMCP steels, users may want to consider welding consumables which avoid under-matched weld metal. Conversely the steels should be amenable to fabrication and welding under shipyard and offshore conditions.

    1.2

    Due to the inherent characteristics of TMCP method, the plates cannot be formed or post-weld heat treated at temperatures above treated at temperature above 1100°F [595°C] without some risk of sustaining irreversible and significant losses in strength and toughness. If warm forming is required, the tensile and notch toughness properties shall conform to the requirements of the specification. The procedure for verification shall be subject to mutual agreement. The plates may be post-weld heat treated at elevated temperatures not exceeding 1100°F [595°C] providing the test coupons are subjected to a thermal cycle to simulate each fabrication operations, as described in S-9. Verification or simulation is not necessary for heating at temperatures not exceeding 400°F [205°C]

    1.3

    The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. (Z direction) Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminations and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptance. The presence of marinations and large non-metallic inclusions in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic examination of the plates by the manufacturer and specifies limits for acceptance. If Supplementary Requirement S-1 is not employed, it is recommended that a fabrication yard ultrasonic examination of plates prior to fit up be specified by the owner so as to permit placement of any detected laminations in areas free from through-thickness loadings.

    1.4

    For application where through-thickness properties are important but not of sufficient concern to justify the expense of Z- direction testing, Supplementary Requirement S-5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S-5 is neither a substitute nor a guarantee of a minimum level of through thickness ductility.

    1.5

    The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperate climate (14°F[-10°C] minimum service temperature). Cold formed materials have less toughness due to straining than that of the original flat plates, especially in those areas aged by the attachment welding of stubs and braces. The requirements in Section 6 take into consideration typical losses in toughness due to straining and aging. Supplementary requirements S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040.

    1.5.11

    For applications with lower service temperatures should be considered Supplementary Requirement S-2 provides for impact tests at temperatures other than specified in Section 6. S2.1 provides for NDTT or Charpy V-notch testing at -60°C. S2.2 provides for such testing at temperatures less than -40°C but other than -60°C.

    1.6

    Preproduction Qualification. Supplementary Requirement s-11 and the related API RP 2Z, dealing with CTOD testing of the weld heat-affected zone and with resistance to hydrogen cracking, respectively, address problems which are not normally dealt with in a “commodity grade” steel specification. These problems are not unique to TMCP steels, but arise because:

    a. Users may be expecting higher performance from TMCP steels than is available with conventional steels (e.g., welding with no preheat, or welding with very high heat inputs while retaining the superior notch toughness), and

    b. This is a performance specification which accommodates a variety of differentiated steelmaking practices, rather than a recipe which completely describes all particulars of chemistry, process, and quality control (essential variables).

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/c59b6435-ca24-4927-84b0-98ca12a56b1d.htm 01-May-87
    API SPEC 2W 2ND ED (1990) Specification for Steel Plates for Offshore Structures; Produced by Thermo Mechanical Control Processing (TMCP); Second Edition 1.1 Coverage

    This specification covers four grades of intermediate strength steel plates for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, lamellar tearing. Grades 42, 50, and 50Tare covered in thicknesses up to 6 in. [150 mm] inclusive, and Grade 60 is covered in thicknesses up to 4 in. [100 mm] inclusive.

    1.1.1

    It is intended that steel produced to Grades 42 and 50T of the basic API Spec 2W, without Supplementary Requirements, although produced in a different manner and of somewhat different chemical compositions, be at least equivalent in minimum performance and, therefore, in service application, to the corresponding grades listed in API Spec 2H. Higher performance (Ie., notch toughness at lower temperatures, or enhanced weldability) typically available with TMCP steel may be achieved by specification of Supplementary Requirements.

    1.1.2

    API 2W steels are intended for fabrication primarily by cold forming and welding. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Because of the characteristic high YS/TS ratio of TMCP steels, users may want to consider welding consumables which avoid under-matched weld metal. Conversely the steels should be amenable to fabrication and welding under shipyard and offshore conditions.

    1.2 Post Manufacturing Heating

    Due to the inherent characteristics of TMCP method, the plates cannot be formed or post-weld heat treated at temperatures above treated at temperature above 1100°F [595°C] without some risk of sustaining irreversible and significant losses in strength and toughness. If warm forming is required, the tensile and notch toughness properties shall conform to the requirements of the specification. The procedure for verification shall be subject to mutual agreement. The plates may be post-weld heat treated at elevated temperatures not exceeding 1100°F [595°C] providing the test coupons are subjected to a thermal cycle to simulate each fabrication operations, as described in S-9. Verification or simulation is not necessary for heating at temperatures not exceeding 400°F [205°C]

    1.3

    The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. (Z direction) Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminations and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptance.

    1.4

    For application where through-thickness properties are important but not of sufficient concern to justify the expense of Z- direction testing, Supplementary Requirement S-5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S-5 is neither a substitute nor a guarantee of a minimum level of through thickness ductility.

    1.5

    The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperate climate (14°F[-10°C] minimum service temperature). Cold formed materials have less toughness due to straining than that of the original flat plates, especially in those areas aged by the attachment welding of stubs and braces. The requirements in Section 6 take into consideration typical losses in toughness due to straining and aging. Supplementary requirements S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040.

    1.5.1

    For applications with lower service temperatures should be considered Supplementary Requirement S-2 provides for impact tests at temperatures other than specified in Section 6. S2.1 provides for NDTT or Charpy V-notch testing at -60°C. S2.2 provides for such testing at temperatures less than -40°C but other than -60°C.

    1.6

    Preproduction Qualification. Supplementary Requirement s-11 and the related API RP 2Z, dealing with CTOD testing of the weld heat-affected zone and with resistance to hydrogen cracking, respectively, address problems which are not normally dealt with in a “commodity grade” steel specification. These problems are not unique to TMCP steels, but arise because:

    a. Users may be expecting higher performance from TMCP steels than is available with conventional steels (e.g., welding with no preheat, or welding with very high heat inputs while retaining the superior notch toughness), and

    b. This is a performance specification which accommodates a variety of differentiated steelmaking practices, rather than a recipe which completely describes all particulars of chemistry, process, and quality control (essential variables). It is intended that supplementary Requirement S-11 shall apply only when specified in advance by the purchaser. In many cases it may be possible to reply on prior data assembled by the steelmaker, provided no essential variables of the process have been changed. 1.7 Manufacturers desiring to apply the API Monogram to products covered by this specification shall demonstrate to the satisfaction of the American Petroleum Institute a program of education, training, experience, and/or examination assuring the manufacturer’s personnel are competent in chemical analysis, inspection, testing and non destructive examinations required or referenced by the specification.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/6cc749a0-91f7-426f-861b-7374aaff9fc5.htm 01-Jul-90
    API SPEC 2W 3RD ED (1993) Specification for Steel Plates for Offshore Structures; Produced by Thermo-Mechanical Control Processing (TMCP); Third Edition 1.1 Coverage

    This specification covers four grades of intermediate strength steel plates for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, lamellar tearing. Grades 42, 50, and 50Tare covered in thicknesses up to 6 in. [150 mm] inclusive, and Grade 60 is covered in thicknesses up to 4 in. [100 mm] inclusive.

    1.1.1

    It is intended that steel produced to Grades 42 and 50T of the basic API Spec 2W, without Supplementary Requirements, although produced in a different manner and of somewhat different chemical compositions, be at least equivalent in minimum performance and, therefore, in service application, to the corresponding grades listed in API Spec 2H. Higher performance (Ie., notch toughness at lower temperatures, or enhanced weldability) typically available with TMCP steel may be achieved by specification of Supplementary Requirements.

    1.1.2

    API 2W steels are intended for fabrication primarily by cold forming and welding. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Because of the characteristic high YS/TS ratio of TMCP steels, users may want to consider welding consumables which avoid under-matched weld metal. Conversely the steels should be amenable to fabrication and welding under shipyard and offshore conditions.

    1.2 Post Manufacturing Heating

    Due to the inherent characteristics of TMCP method, the plates cannot be formed or post-weld heat treated at temperatures above treated at temperature above 1100°F [595°C] without some risk of sustaining irreversible and significant losses in strength and toughness. If warm forming is required, the tensile and notch toughness properties shall conform to the requirements of the specification. The procedure for verification shall be subject to mutual agreement. The plates may be post-weld heat treated at elevated temperatures not exceeding 1100°F [595°C] providing the test coupons are subjected to a thermal cycle to simulate each fabrication operations, as described in S-9. Verification or simulation is not necessary for heating at temperatures not exceeding 400°F [205°C]

    1.3

    The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. (Z direction) Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminations and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptance.

    1.4For application where through-thickness properties are important but not of sufficient concern to justify the expense of Z- direction testing, Supplementary Requirement S-5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S-5 is neither a substitute nor a guarantee of a minimum level of through thickness ductility.

    1.5

    The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperate climate (14°F[-10°C] minimum service temperature). Cold formed materials have less toughness due to straining than that of the original flat plates, especially in those areas aged by the attachment welding of stubs and braces. The requirements in Section 6 take into consideration typical losses in toughness due to straining and aging. Supplementary requirements S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040.

    1.5.11

    For applications with lower service temperatures should be considered Supplementary Requirement S-2 provides for impact tests at temperatures other than specified in Section 6. S2.1 provides for NDTT or Charpy V-notch testing at -60°C. S2.2 provides for such testing at temperatures less than -40°C but other than -60°C.

    1.6

    Preproduction Qualification. Supplementary Requirement s-11 and the related API RP 2Z, dealing with CTOD testing of the weld heat-affected zone and with resistance to hydrogen cracking, respectively, address problems which are not normally dealt with in a “commodity grade” steel specification. These problems are not unique to TMCP steels, but arise because:

    a.

    Users may be expecting higher performance from TMCP steels than is available with conventional steels (e.g., welding with no preheat, or welding with very high heat inputs while retaining the superior notch toughness), and

    b. This is a performance specification which accommodates a variety of differentiated steelmaking practices, rather than a recipe which completely describes all particulars of chemistry, process, and quality control (essential variables). It is intended that supplementary Requirement S-11 shall apply only when specified in advance by the purchaser. In many cases it may be possible to reply on prior data assembled by the steelmaker, provided no essential variables of the process have been changed. 1.7 Manufacturers desiring to apply the API Monogram to products covered by this specification shall demonstrate to the satisfaction of the American Petroleum Institute a program of education, training, experience, and/or examination assuring the manufacturer’s personnel are competent in chemical analysis, inspection, testing and non destructive examinations required or referenced by the specification.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/7d1d3b92-eb27-4703-ab2d-63e1235d54ff.htm 01-Jul-93
    API SPEC 2W 4TH ED (1999) Specification for Steel Plates for Offshore Structures; Produced by Thermo Mechanical Control Processing (TMCP); Fourth Edition; Effective Date; Februrary 1, 2000 1.1 Coverage

    This specification covers four grades of intermediate strength steel plates for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, lamellar tearing. Grades 42, 50, and 50Tare covered in thicknesses up to 6 in. [150 mm] inclusive, and Grade 60 is covered in thicknesses up to 4 in. [100 mm] inclusive.

    1.1.1

    It is intended that steel produced to Grades 42 and 50T of the basic API Spec 2W, without Supplementary Requirements, although produced in a different manner and of somewhat different chemical compositions, be at least equivalent in minimum performance and, therefore, in service application, to the corresponding grades listed in API Spec 2H. Higher performance (Ie., notch toughness at lower temperatures, or enhanced weldability) typically available with TMCP steel may be achieved by specification of Supplementary Requirements. 1.1.2 API 2W steels are intended for fabrication primarily by cold forming and welding. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Because of the characteristic high YS/TS ratio of TMCP steels, users may want to consider welding consumables which avoid under-matched weld metal. Conversely the steels should be amenable to fabrication and welding under shipyard and offshore conditions. 1.2 Post Manufacturing Heating

    1.2.1 Due to the inherent characteristics of TMCP method, the plates cannot be formed or post-weld heat treated at temperatures above treated at temperature above 1100°F [595°C] without some risk of sustaining irreversible and significant losses in strength and toughness. If warm forming is required, the tensile and notch toughness properties shall conform to the requirements of the specification. The procedure for verification shall be subject to mutual agreement. The plates may be post-weld heat treated at elevated temperatures not exceeding 1100°F [595°C] providing the test coupons are subjected to a thermal cycle to simulate each fabrication operations, as described in S-9. Verification or simulation is not necessary for heating at temperatures not exceeding 400°F [205°C] 1.2.2 The primary use of this steel is in tubular joints where portions of the plates will be subject to tension in the thickness direction. (Z direction) Supplementary Requirement S-4 provides for through-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminations and large non metallic inclusion in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptance. 1.2.3 For applications where through-thickness properties are important but not of sufficient concern to justify the expense of Z- direction testing, Supplementary Requirement S-5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S-5 is neither a substitute nor a guarantee of a minimum level of through thickness ductility. 1.2.4 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperate climate (14°F[-10°C] minimum service temperature). Cold formed materials have less toughness due to straining than that of the original flat plates, especially in those areas aged by the attachment welding of stubs and braces. The requirements in Section 6 take into consideration typical losses in toughness due to straining and aging. Supplementary requirements S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040. 1.2.4.1 For applications with lower service temperatures should be considered Supplementary Requirement S-2 provides for impact tests at temperatures other than specified in Section 6. S2.1 provides for NDTT or Charpy V-notch testing at -60°C. S2.2 provides for such testing at temperatures less than -40°C but other than -60°C. 1.6 Preproduction Qualification. Supplementary Requirement s-11 and the related API RP 2Z, dealing with CTOD testing of the weld heat-affected zone and with resistance to hydrogen cracking, respectively, address problems which are not normally dealt with in a “commodity grade” steel specification. These problems are not unique to TMCP steels, but arise because: a. Users may be expecting higher performance from TMCP steels than is available with conventional steels (e.g., superior notch toughness), and

    b. This is a performance specification which accommodates a variety of differentiated steelmaking practices, rather than a recipe which completely describes all particulars of chemistry, process, and quality control (essential variables). It is intended that supplementary Requirement S-11 shall apply only when specified in advance by the purchaser. In many cases it may be possible to reply on prior data assembled by the steelmaker, provided no essential variables of the process have been changed.

    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/7902bf28-d256-4028-8eb4-61141a776977.htm 01-Aug-99
    API SPEC 2W 5TH ED (R 2012) Specification for Steel Plates for Offshore Structures, Produced by Thermo-Mechanical Control Processing (TMCP); Fifth Edition; Reaffirmed, January 2012 1.1 COVERAGE

    This specification covers two grades of high strength steel plates for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, and lamellar tearing. Grade 50 is covered in thicknesses up to 6 in. (150 mm) inclusive, and Grade 60 is covered in thicknesses up to 4 in. (100 mm) inclusive.

    1.1.1

    It is intended that steel produced to Grades 50 of the basic API Spec 2W, without Supplementary Requirements, although produced in a different manner and of somewhat different chemical compositions, be at least equivalent in minimum performance and, therefore, in service application, to the corresponding grades listed in Sections 5 through 7 of API Spec 2H. Higher performance (i.e., notch toughness at lower temperatures, or enhanced weldability) typically available with TMCP steel may be achieved by specification of Supplementary Requirements.

    1.1.2

    API Spec 2W steels are intended for fabrication primarily by cold forming and welding. The welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Because of the characteristic high YS/TS ratio of TMCP steels, users may want to consider welding consumables which avoid under-matched weld metal. Conversely, the steels should be amendable to fabrication and welding under shipyard and offshore conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC/6c9f7cd8-57d6-44ea-8e1e-5bdd1cc14a30.htm 01-Jan-12
    API SPEC 2W 6TH ED (2019) Steel Plates Produced by Thermo-Mechanically Controlled Processing for Offshore Structures; Sixth Edition 1.1 COVERAGE

    This specification covers two grades of high strength steel plates for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, and lamellar tearing. Grade 50 is covered in thicknesses up to 6 in. (150 mm) inclusive, and Grade 60 is covered in thicknesses up to 4 in. (100 mm) inclusive.

    1.1.1

    It is intended that steel produced to Grades 50 of the basic API Spec 2W, without Supplementary Requirements, although produced in a different manner and of somewhat different chemical compositions, be at least equivalent in minimum performance and, therefore, in service application, to the corresponding grades listed in Sections 5 through 7 of API Spec 2H. Higher performance (i.e., notch toughness at lower temperatures, or enhanced weldability) typically available with TMCP steel may be achieved by specification of Supplementary Requirements.

    1.1.2

    API Spec 2W steels are intended for fabrication primarily by cold forming and welding. The welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Because of the characteristic high YS/TS ratio of TMCP steels, users may want to consider welding consumables which avoid under-matched weld metal. Conversely, the steels should be amendable to fabrication and welding under shipyard and offshore conditions.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/61e3faa8-f7b0-4fe7-ae84-b1b8ffccad81.htm 01-Jan-19
    API SPEC 2Y 1ST ED (1987) Specification for Steel Plates Quenched-and-Tempered for offshore Structures; First Edition 1.1 Coverage This specification covers four grades of intermediate strength steel plates for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, lamellar tearing. Grades 42, 50, and 50Tare covered in thicknesses up to 6 in. [150 mm] inclusive, and Grade 60 is covered in thicknesses up to 4 in. [100 mm] inclusive.

    1.1.1 It is intended that steel produced to Grades 42 and 50T of the basic API Spec 2W, without Supplementary Requirements, although produced in a different manner and of somewhat different chemical compositions, be at least equivalent in minimum performance and, therefore, in service application, to the corresponding grades listed in API Spec 2H and API 2W.

    1.1.2 API 2Y steels are intended for fabrication primarily by cold forming and welding. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Because of the characteristic high YS/TS ratio of quenched-and-tempered steels, users may want to consider welding consumables which avoid under-matched weld metal. Conversely the steels should be amendable to fabrication and welding under shipyard and offshore conditions.

    1.2 Post Manufacturing Heating Due to the inherent characteristics of quench-and-tempered material, the plates cannot be formed or post-weld heat treated at temperatures above tempering temperature used without some risk of sustaining irreversible and significant losses in strength and toughness. If warm forming is required, the tensile and notch toughness properties shall conform to the requirements of the specification. The procedure for verification shall be subject to mutual agreement. The plates may be post-weld heat treated at elevated temperatures used providing the providing the test coupons are subjected to a thermal cycle to simulate each fabrication operations, as described in S-9. Verification or simulation is not necessary for heating at temperatures not exceeding 400°F [205°C]

    1.3 The primary use of this steel is in tubular joints, stiffened plate construction, and other intersections where portions of the plates will be subject to tension in the thickness direction. (Z direction) Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminations and large non-metallic inclusions in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptance. If Supplementary Requirement S-1 is not employed, it is recommended that a fabrication yard ultrasonic examination of plates prior to fit up be specified by the owner so as to permit placement of any detected laminations in areas free from through-thickness loadings.

    1.4 For applications where through-thickness properties are important but not of sufficient concern to justify the expense of Z- direction testing, Supplementary Requirement S-5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S-5 is neither a substitute for S-4 Through Thickness Testing nor a guarantee of a minimum level of through thickness ductility.

    1.5 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperate climate (14°F[-10°C] minimum service temperature). Cold formed materials have less toughness due to straining than that of the original flat plates, especially in those areas aged by the attachment welding of stubs and braces. The requirements in Section 6 take into consideration typical losses in toughness due to straining and aging. Supplementary Requirements S7 and S8 deal with the strain aging problem, and consideration should be given invoking S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040.

    1.6 Preproduction Qualification. Supplementary Requirement s-11 and the related API RP 2Z, dealing with CTOD testing of the weld heat-affected zone and with resistance to hydrogen cracking, respectively, address problems which are not normally dealt with in a “commodity grade” steel specification. These problems are not unique to Q&T steels, but arise because:

    a. Users may be expecting higher performance from Q&T steels than is available with conventional steels (e.g., superior notch toughness), and

    b. This is a performance specification which accommodates a variety of differentiated steelmaking practices, rather than a recipe which completely describes all particulars of chemistry, process, and quality control (essential variables).

    It is intended that supplementary Requirement S-11 shall apply only when specified in advance by the purchaser. In many cases it may be possible to reply on prior data assembled by the steelmaker, provided no essential variables of the process have been changed.

    1.7 American Petroleum Institute (API) specifications are published as an aid to procurement of standardized equipment and materials. These specifications are not intended to inhibit purchasers and procedures from purchasing or producing products made to specifications other than API, and nothing in any API specification is intended in any way inhibit the purchase of products from companies not authorized to use the API monogram.

    1.8 Nothing contained in any API, specification is to be construed as granting any right, by implication or otherwise , for the manufacture, Sale, or use in connection with any method, apparatus or product covered by letters patent, nor as insuring anyone against liability for infringement of letters patent.

    1.9 API specifications may be used by anyone desiring to do so, and every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them. However, the Institute makes no representation, warranty or guarantee in connection with the publication of any API specification and hereby expressly disclaims any liability or responsibility for loss or damage resulting from their use, for any violation of federal, state or municipal regulation with which an API specification may conflict, or for the infringement of any patent resulting from the use of an API specification.

    1.10 The use of the API monogram is a warranty by the manufacturer to the purchaser that the manufacturer has obtained a license to use the monogram and, further, that the product which bears monogram conforms to the applicable API Specification. However, the American Petroleum Institute does not represent, warrant or guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/f24cafa4-838a-45bc-adec-186072e06298.htm 01-May-87
    API SPEC 2Y 2ND ED (1990) Specification for Steel Plates. Quenched-and-Tempered for Offshore Structures; Second Edition This specification covers four grades of intermediate strength steel plates for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, lamellar tearing. Grades 42, 50, and 50Tare covered in thicknesses up to 6 in. [150 mm] inclusive, and Grade 60 is covered in thicknesses up to 4 in. [100 mm] inclusive.

    1.1.1 It is intended that steel produced to Grades 42 and 50T of the basic API Spec 2W, without Supplementary Requirements, although produced in a different manner and of somewhat different chemical compositions, be at least equivalent in minimum performance and, therefore, in service application, to the corresponding grades listed in API Spec 2H and API 2W.

    1.1.2 API 2Y steels are intended for fabrication primarily by cold forming and welding. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Because of the characteristic high YS/TS ratio of quenched-and-tempered steels, users may want to consider welding consumables which avoid under-matched weld metal. Conversely the steels should be amendable to fabrication and welding under shipyard and offshore conditions.

    1.2 Post Manufacturing Heating Due to the inherent characteristics of quench-and-tempered material, the plates cannot be formed or post-weld heat treated at temperatures above tempering temperature used without some risk of sustaining irreversible and significant losses in strength and toughness. If warm forming is required, the tensile and notch toughness properties shall conform to the requirements of the specification. The procedure for verification shall be subject to mutual agreement. The plates may be post-weld heat treated at elevated temperatures used providing the providing the test coupons are subjected to a thermal cycle to simulate each fabrication operations, as described in S-9. Verification or simulation is not necessary for heating at temperatures not exceeding 400°F [205°C]

    1.3 The primary use of this steel is in tubular joints, stiffened plate construction, and other intersections where portions of the plates will be subject to tension in the thickness direction. (Z direction) Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminations and large non-metallic inclusions in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptance. If Supplementary Requirement S-1 is not employed, it is recommended that a fabrication yard ultrasonic examination of plates prior to fit up be specified by the owner so as to permit placement of any detected laminations in areas free from through-thickness loadings.

    1.4 For applications where through-thickness properties are important but not of sufficient concern to justify the expense of Z- direction testing, Supplementary Requirement S-5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S-5 is neither a substitute for S-4 Through Thickness Testing nor a guarantee of a minimum level of through thickness ductility.

    1.5 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperate climate (14°F[-10°C] minimum service temperature). Cold formed materials have less toughness due to straining than that of the original flat plates, especially in those areas aged by the attachment welding of stubs and braces. The requirements in Section 6 take into consideration typical losses in toughness due to straining and aging. Supplementary Requirements S7 and S8 deal with the strain aging problem, and consideration should be given invoking S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040.

    1.5.1 For applications with lower service temperatures should be considered. Supplementary Requirement S-2 provides for impact tests at temperatures other than specified in Section 6 or Supplementary Requirement S-12. S2.1 provides for Drop-Weight or Charpy V-notch testing at -60°C. S2.2 provides for such testing at temperatures less than -40°C but other than -60°C.

    1.6Preproduction Qualification. Supplementary Requirement S-11 and Section 3 API RP 2Z, dealing with CTOD testing of the weld heat-affected zone and with resistance to hydrogen cracking, respectively, address problems which are not normally dealt with in a “commodity grade” steel specification. These problems are not unique to Q&T steels, but arise because:

    a. Users may be expecting higher performance from Q&T steels than is available with conventional steels (e.g., welding with no preheat, or welding with very high heat inputs while retaining the superior notch toughness), and

    b. This is a performance specification which accommodates a variety of differentiated steelmaking practices, rather than a recipe which completely describes all particulars of chemistry, process, and quality control (essential variables).

    It is intended that supplementary Requirement S-11 shall apply only when specified in advance by the purchaser. In many cases it may be possible to reply on prior data assembled by the steelmaker, provided no essential variables of the process have been changed.

    1.7 Manufacturers desiring to apply the API Monogram to products covered by this specification shall demonstrate to the satisfaction of the American Petroleum Institute a program of education, training, experience, and/ or examination assuring the manufacturers personnel are competent in chemical analysis, inspection, and nondestructive examinations required or referenced by this specification.


    http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/ff73316b-5de4-446f-9c1a-7f5dcbfc1d44.htm 01-Jul-90
    API SPEC 2Y 3RD ED (1993) Specification for Steel Plates, Quenched-and-Tempered for Offshore Structures; Third Edition 1.1 Coverage This specification covers four grades of intermediate strength steel plates for use in welded construction of offshore structures, in selected critical portions which must resist impact, plastic fatigue loading, lamellar tearing. Grades 42, 50, and 50Tare covered in thicknesses up to 6 in. [150 mm] inclusive, and Grade 60 is covered in thicknesses up to 4 in. [100 mm] inclusive.

    1.1.1 It is intended that steel produced to Grades 42 and 50T of the basic API Spec 2W, without Supplementary Requirements, although produced in a different manner and of somewhat different chemical compositions, be at least equivalent in minimum performance and, therefore, in service application, to the corresponding grades listed in API Spec 2H and API 2W.

    1.1.2 API 2Y steels are intended for fabrication primarily by cold forming and welding. Welding procedure is of fundamental importance and it is presumed that procedures will be suitable for the steels and their intended service. Because of the characteristic high YS/TS ratio of quenched-and-tempered steels, users may want to consider welding consumables which avoid under-matched weld metal. Conversely the steels should be amendable to fabrication and welding under shipyard and offshore conditions.

    1.2 Post Manufacturing HeatingDue to the inherent characteristics of quench-and-tempered material, the plates cannot be formed or post-weld heat treated at temperatures above tempering temperature used without some risk of sustaining irreversible and significant losses in strength and toughness. If warm forming is required, the tensile and notch toughness properties shall conform to the requirements of the specification. The procedure for verification shall be subject to mutual agreement. The plates may be post-weld heat treated at elevated temperatures used providing the providing the test coupons are subjected to a thermal cycle to simulate each fabrication operations, as described in S-9. Verification or simulation is not necessary for heating at temperatures not exceeding 400°F [205°C]

    1.3 The primary use of this steel is in tubular joints, stiffened plate construction, and other intersections where portions of the plates will be subject to tension in the thickness direction. (Z direction) Supplementary Requirement S-4 provides for thru-thickness testing of plates by the manufacturer and specifies limits for rejection. The presence of laminations and large non-metallic inclusions in these portions of the plates can be extremely damaging. Supplementary Requirement S-1 provides for ultrasonic inspection of those plates by the manufacturer and specifies limits for acceptance. If Supplementary Requirement S-1 is not employed, it is recommended that a fabrication yard ultrasonic examination of plates prior to fit up be specified by the owner so as to permit placement of any detected laminations in areas free from through-thickness loadings.

    1.4 For applications where through-thickness properties are important but not of sufficient concern to justify the expense of Z- direction testing, Supplementary Requirement S-5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S-5 is neither a substitute for S-4 Through Thickness Testing nor a guarantee of a minimum level of through thickness ductility.

    1.5 The notch toughness requirements specified in Section 6 are suitable for application below water or above water in areas of temperate climate (14°F[-10°C] minimum service temperature). Cold formed materials have less toughness due to straining than that of the original flat plates, especially in those areas aged by the attachment welding of stubs and braces. The requirements in Section 6 take into consideration typical losses in toughness due to straining and aging. Supplementary Requirements S7 and S8 deal with the strain aging problem, and consideration should be given invoking S-7 and/ or S-8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040.

    1.5.1 For applications with lower service temperatures should be considered. Supplementary Requirement S-2 provides for impact tests at temperatures other than specified in Section 6 or Supplementary Requirement S-12. S2.1 provides for Drop-Weight or Charpy V-notch testing at -60°C. S2.2 provides for such testing at temperatures less than -40°C but other than -60°C.

    1.6<