Jul. 08, 2024
Mechanical Parts & Fabrication Services
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.
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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 (API 6A, 15th Edition) is outside the scope of this document.
This standard is not applicable to onsite repair at the equipment installation site.
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.
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.
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.
Placement and Stop-collar Testing; First Edition
This part of ISO 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.
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.
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.
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 :. 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.
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.
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.
This part of ISO 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 is intended for the use of manufacturers, service companies and end-users of heavy brines.
This International Standard is not applicable to repair activities.
NOTE ISO provides requirements for SSSV equipment repair.
This International Standard is not applicable to repair activities.
NOTE ISO provides requirements for SSSV equipment repair.
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 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.
recommendations for development of complete subsea production systems, from the design phase to decommissioning and abandonment. This part of ISO is intended as an umbrella document to govern other parts of ISO 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 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 are in conflict with, or are inconsistent with, requirements as stated in the relevant complementary parts of ISO , then the specific requirements in the complementary parts take precedence.
This part of ISO 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 applies to flexible pipe systems, including ancillary components.
The applications covered by this part of ISO are sweet- and sour-service production, including export and injection applications. This part of ISO applies to both static and dynamic flexible pipe systems used as flowlines, risers and jumpers. This part of ISO 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 does not cover flexible pipes for use in choke and kill lines or umbilical and control lines.
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 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 .
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 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 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 .
Specific equipment covered by this part of ISO 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 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.
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 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 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 .
Specific equipment covered by this part of ISO 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 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.
This part of ISO 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 .
This part of ISO 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 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 :
&#; 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 -1 and API Spec 2C.
NOTE &#;Proppants&#; mentioned henceforth in this part of ISO 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 is to provide a consistent methodology for testing performed on hydraulic fracturing and/or gravel-packing proppants.
NOTE &#;Proppants&#; mentioned henceforth in this part of ISO 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 is to provide a consistent methodology for testing performed on hydraulic fracturing and/or gravel-packing proppants.
NOTE The &#;proppants&#; mentioned henceforth in this part of ISO 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 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.
NOTE The "proppants" mentioned henceforth in this part of ISO 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 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.
The content and coverage of several industry documents are compiled and refined within ISO (all parts).
The content and coverage of several industry documents are compiled and refined within ISO (all parts).
This part of ISO 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 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.
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 -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.
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 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:
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.
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.
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.
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.
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.
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 -1 (Identical), Petroleum and natural gas industries&#;Cements and materials for well cementing&#;Part 1: Specification (includes ISO errata).
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.
This standard is not applicable to rigid or positive centralizers.
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.
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:
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 .
Where applicable, this part of ISO 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 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 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 .
The following equipment is outside the scope of this part of ISO :
&#; 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 is not applicable to the rework and repair of used equipment.
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 .
Where applicable, this part of ISO 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 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 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 .
The following equipment is outside the scope of this part of ISO :
&#; 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 is not applicable to the rework and repair of used equipment.
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 .
Where applicable, this part of ISO 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 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 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 .
The following equipment is outside the scope of this part of ISO :
&#; 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 is not applicable to the rework and repair of used equipment.
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 .
Where applicable, this part of ISO 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 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 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 .
The following equipment is outside the scope of this part of ISO :
&#; 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 is not applicable to the rework and repair of used equipment.
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 .
Where applicable, this part of ISO 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 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 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 .
The following equipment is outside the scope of this part of ISO :
&#; 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 is not applicable to the rework and repair of used equipment.
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 .
Where applicable, this part of ISO 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 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 -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 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 .
The following equipment is outside the scope of this part of ISO :
&#; 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 is not applicable to the rework and repair of used equipment.
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 .
Where applicable, this part of ISO 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 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 -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 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 .
The following equipment is outside the scope of this part of ISO :
&#; 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 is not applicable to the rework and repair of used equipment.
This part of ISO 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 .
Where applicable, this part of ISO can also be used for equipment on satellite, cluster arrangements and multiple well template applications.
This part of ISO 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 .
Where applicable, this part of ISO can also be used for equipment on satellite, cluster arrangements and multiple well template applications.
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 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 applies to umbilicals for static or dynamic service, with surface-surface, surface-subsea and subsea-subsea routings.
This part of ISO 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 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 does not apply to a tube or hose rated lower than 7 MPa (1 015 psi).
This part of ISO 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 -1 and IEC -2.
installation and operation of subsea production control systems.
This part of ISO 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 can be used for equipment on multiple-well applications.
This part of ISO 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 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 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 .
This part of ISO applies to unbonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. This part of ISO does not cover flexible pipes of bonded structure. This part of ISO 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 -11.
This part of ISO 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 are sweet and sour service production, including export and injection applications. Production products include oil, gas, water and injection chemicals. This part of ISO applies to both static and dynamic flexible pipes used as flowlines, risers and jumpers. This part of ISO 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 -10 provides guidelines for bonded flexible pipe.
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 -11 for guidelines on the use of flexible pipes and ancillary components.
This part of ISO applies to unbonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. This part of ISO does not cover flexible pipes of bonded structure. This part of ISO 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 -11.
This part of ISO 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 are sweet and sour service production, including export and injection applications. Production products include oil, gas, water and injection chemicals. This part of ISO applies to both static and dynamic flexible pipes used as flowlines, risers and jumpers. This part of ISO 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 -10 provides guidelines for bonded flexible pipe.
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 -11 for guidelines on the use of flexible pipes and ancillary components.
This part of ISO applies to unbonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. This part of ISO does not cover flexible pipes of bonded structure. This part of ISO 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 -11.
This part of ISO 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 are sweet and sour service production, including export and injection applications. Production products include oil, gas, water and injection chemicals. This part of ISO applies to both static and dynamic flexible pipes used as flowlines, risers and jumpers. This part of ISO 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 -10 provides guidelines for bonded flexible pipe.
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 -11 for guidelines on the use of flexible pipes and ancillary components.
This part of ISO applies to unbonded flexible pipe assemblies, consisting of segments of flexible pipe body with end fittings attached to both ends. This part of ISO does not cover flexible pipes of bonded structure. This part of ISO 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 -11.
This part of ISO 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 are sweet and sour service production, including export and injection applications. Production products include oil, gas, water and injection chemicals. This part of ISO applies to both static and dynamic flexible pipes used as flowlines, risers and jumpers. This part of ISO 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 -10 provides guidelines for bonded flexible pipe.
1.1.1 This part of ISO 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.
1.1.1 This part of ISO 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.
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.
This part of ISO 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 . Additionally, this part of ISO does not include specifications for centre-set mandrels, or mandrels that employ or support tubing-retrievable flow control devices.
This part of ISO 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 refers are independent devices that can accept installation of flow-control or other devices down-hole.
This part of ISO 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 . Additionally, this part of ISO does not include specifications for centre-set mandrels, or mandrels that employ or support tubing-retrievable flow control devices.
This part of ISO 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 refers are independent devices that can accept installation of flow-control or other devices down-hole.
The installation and retrieval of flow-control devices is outside the scope of this part of ISO . Additionally, this part of ISO is not applicable to flow-control devices used in centre-set mandrels or with tubing-retrievable applications.
This part of ISO 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 .
The installation and retrieval of flow-control devices is outside the scope of this part of ISO . Additionally, this part of ISO is not applicable to flow-control devices used in centre-set mandrels or with tubing-retrievable applications.
This part of ISO 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 .
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 . Centre-set and tubing-retrievable mandrel applications are not covered.
This part of ISO 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 . Centre-set and tubing-retrievable mandrel applications are not covered.
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.
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.
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 , ISO , ISO , ISO , ISO 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.
&#; 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 -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 -1 and ISO -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 -3 and are, therefore, not included in PSL-2.
&#; 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 -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 -1 and ISO -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 -3 and are, therefore, not included in PSL-2.
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.
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.
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.
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 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 is applicable is shown in Figure 1.
This part of 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 is applicable is shown in Figure 1.
This part of 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 is applicable is shown in Figure 1.
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.
&#; 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 or API 5CT, ISO or API 5D, and ISO 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 or API 5CT, ISO or API 5D, and ISO 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 or API 5CT, ISO or API 5D and ISO 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.
&#; 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 or API 5CT, ISO or API 5D, and ISO 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 or API 5CT, ISO or API 5D, and ISO 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.
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.
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, ,M.R.I Project No. -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- dated August, 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
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 Standardization Conference. A description of the specimen, the test apparatus, and the procedure is given in Appendix A.
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
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
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
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.
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.
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.
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.
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--fd.htm 01-Aug-48 API BUL 5C2 5TH ED () 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.
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--b4a0-d846b1e.htm 01-Jul-56 API BUL 5C2 7TH ED () 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.
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.
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.
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.
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.
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.
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.
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.
Additionally, containment issues for operations below the water line are outside the scope of this document.
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.
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.
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.
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.
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.
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, ). 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, ) 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., ). Eighty-seven percent of all wetland losses between and 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, ).
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.
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 and its peak in (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 , 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 proven reserves were 90 billion barrels, sufficient to sustain production at the rate for about 24 years. By , reserves had expanded to nearly a trillion barrels, sufficient to support 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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
This RP covers the vibration limits, testing, and analysis of ESP systems and subsystems.
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.
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.
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).
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.
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 &#;Gas Lift Equipment Specifications
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 ). 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
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.
This recommended practice is organized to follow the tests as listed on the API Drilling Mud Report form (API RP 13G, Third Edition, February ). 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.
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).
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).
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).
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).
The procedure described in this standard is not intended for the comparison of similar types of individual pieces of equipment.
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 , 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.
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.
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.
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.
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.
This International Standard is not applicable to repair activities.
NOTE: ISO provides requirements for SSSV equipment repair.
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.
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.
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.
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.
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.
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.
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.
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.
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), edition, except where specific departures are noted.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 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.
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 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.
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.
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.
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.
Sections 1 through 4 of this RP are directly applicable to most floating drilling operations. For deepwater locations (exceeding 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).
Sections 1 through 4 of this RP are directly applicable to most floating drilling operations. For deepwater locations (exceeding 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).
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.
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.
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.
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.
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.
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.
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.
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.
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:; API 17K: and in API 17B.
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 , 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.
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 , 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.
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 , 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.
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.
The file count for this data sheet set is 1.
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).
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.
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.
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 ; 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.
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.
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.
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.
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.
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.
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.
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.
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
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>
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.
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.
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.
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.
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 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.
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 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:
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.
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 [ 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.
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 [ 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.
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 -2 document is applicable to the U.S. OCS. Where necessary, this document provides guidance for aligning the ISO -2 requirements and terminology with API. The key differences are as follows.
a) API 2EQ adopts the ISO -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 -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 years. In such cases, these maps may be used with corresponding scale factors to determine appropriate seismic actions for the design of a structure.
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 -2 document is applicable to the U.S. OCS. Where necessary, this document provides guidance for aligning the ISO -2 requirements and terminology with API. The key differences are as follows.
a) API 2EQ adopts the ISO -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 -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 years. In such cases, these maps may be used with corresponding scale factors to determine appropriate seismic actions for the design of a structure.
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.
&#; 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.
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.
&#; 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
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.
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--f91e4bee.htm 01-Nov-14 API RP 2MET 2ND ED () Derivation of Metocean Design and Operating Conditions; Second Edition; ISO -1: 1 ScopeThis 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:
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:
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.
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.
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).
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.
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.
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.
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.
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.
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 TM-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.
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 .119) that must be considered in gas plant design and operations.
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.&#;
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.
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.
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.
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.
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.
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).
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.
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, South Creek Drive, P.O. Box , Houston, Texas - .
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 , IADC/SPE ).
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 , IADC/SPE ).
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.
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.
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.
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.
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).
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).
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.
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.
The engineering solution, which prevents the mating of female 2-inch Figure 402, 2-inch Figure 602 and/or 2-inch Figure subs with the wing nut of the 2-inch Figure 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.
The engineering solution, which prevents the mating of female 2-inch Figure 402, 2-inch Figure 602 and/or 2-inch Figure subs with the wing nut of the 2-inch Figure 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.
The engineering solution, which prevents the mating of female 2-inch Figure 402, 2-inch Figure 602 and/or 2-inch Figure subs with the wing nut of the 2-inch Figure 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
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
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Suggested reading: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.
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.
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.
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.
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.
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.
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.
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).
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.
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.
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.
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 (). This guidance also addresses documentation expectations.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 ft/min and the speed of any shaft does not exceed 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.
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 ft/min and the speed of any shaft does not exceed 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.
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.
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.
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.
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.
Thirteenth Edition; Effective Date: July1.1 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.
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.
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.
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.)
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
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
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
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 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 .
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.
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 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 .
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.
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 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.
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 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.
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.
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.
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.
cast (CC) fiberglass line pipe and fittings for pipe in diameters up to and including 24 in. in diameter and up to and including psig cyclic operating pressures. In addition, at the manufacturer's option, the pipe may also be rated for static operating pressures up to 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 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.
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.
a) PEX line pipe;
b) fittings.
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.
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.
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.
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.
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.
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.
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.
Technical content provides the minimum requirements for performance, design, materials, welding, testing, inspection, storing and shipping.
Technical content provides the minimum requirements for performance, design, materials, welding, testing, inspection, storing and shipping.
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.
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.
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.
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.
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.
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.
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.
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.
fabrication of marine drilling riser equipment used in conjunction with a subsea blowout preventer (BOP) stack.
fabrication of marine drilling riser equipment used in conjunction with a subsea blowout preventer (BOP) stack.
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.
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.
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.
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.
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.
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 ( 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.
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 ( 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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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 , ISO , ISO , ISO , ISO , 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.
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 , ISO , ISO , ISO , ISO , 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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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
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
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
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
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.
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.
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.
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/c12-cea5-41ac-a42c-84cfab.htm 01-Mar-79 API SPEC 2H 3RD ED () 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 () 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--4d04-b3d7-f1b.htm 01-Apr-86 API SPEC 2H 5TH ED () 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.
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.
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/c532-322c-4f6d-8da9-879bf3ad581b.htm 01-Jul-93 API SPEC 2H 8TH ED () 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.
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).
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).
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.
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 ¡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.
1.1 This speci&#;cation covers rolled shapes (wide &#;ange shapes, angles, etc.), having a speci&#;ed 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 speci&#;ed, 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- &#;ed 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 quali&#;ca- tion under AWS D1.1, until AWS cites this speci&#;cation, use the following:
1.4 When heat straightening, hot or warm forming, or post- weld heat treatment above °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 speci&#;cation 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.
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 °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.
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.
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.
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 °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 °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/c59b-ca24--84b0-98ca12a56b1d.htm 01-May-87 API SPEC 2W 2ND ED () Specification for Steel Plates for Offshore Structures; Produced by Thermo Mechanical Control Processing (TMCP); Second Edition 1.1 CoverageThis 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 °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 °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-aaff9fc5.htm 01-Jul-90 API SPEC 2W 3RD ED () Specification for Steel Plates for Offshore Structures; Produced by Thermo-Mechanical Control Processing (TMCP); Third Edition 1.1 CoverageThis 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 °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 °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--ab2d-63ed54ff.htm 01-Jul-93 API SPEC 2W 4TH ED () Specification for Steel Plates for Offshore Structures; Produced by Thermo Mechanical Control Processing (TMCP); Fourth Edition; Effective Date; Februrary 1, 1.1 CoverageThis 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 °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 °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/bf28-d256--8eb4-a.htm 01-Aug-99 API SPEC 2W 5TH ED (R ) Specification for Steel Plates for Offshore Structures, Produced by Thermo-Mechanical Control Processing (TMCP); Fifth Edition; Reaffirmed, January 1.1 COVERAGEThis 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.
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.
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.
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.
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 Preproduction 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., 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.
1.1.1 It is intended that steel produced to Grades 42 and 50T of the basic API Spec 2Y, without Supplementary Requirements, 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 and API Spec 2W.
1.1.2 API 2Y 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 quenched-and- tempered steels, users may want to consider welding consumables which avoid undermatched 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 quenched-andtempered material, plates manufactured to this spec cannot be formed or post-weld heat treated at temperatures above the tempering temperature used during manufacture without some risk of sustaining irreversible and significant losses in strength and toughness. If warm-forming is to be required, the tensile and notch toughness properties of the finished component shall be verified and the properties shall conform to the requirements of the specification. The plates may be post-weld heat treated at a temperature higher than that used during manufacture, providing the test coupons are subjected to a thermal cycle to simulate such fabrication operations, as described in S9. Verification or simulation is not necessary for heating at temperatures not exceeding 400°F (205°C).
1.2.2 The primary use of these steels 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 S4 provides for through-thickness (Z-direction) testing of the plates by the manufacturer and specifies limits for acceptance. Supplementary Requirement S1 provides for ultrasonic examination of the plates by the manufacturer and specifies limits for acceptance.
1.2.3 For applications where through-thickness properties are important but Z-direction testing has not been specified, Supplementary Requirement S5 provides a low-sulfur chemistry intended to reduce the size and number of sulfide inclusions in the plate. Supplement S5 is neither a substitute for S4, Through Thickness Testing, 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 for plates in Section 7 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 to invoking S7 and/or S8 when the strain exceeds 5% or when (Nitrogen x % strain) exceeds 0.040.
1.2.5 For application with lower service temperatures, lower test 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.
1.3Preproduction 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., 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.
This specification covers two grades of high strength steel plate 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 Grade 50 of the basic API Spec 2Y, without Supplementary Requirements, 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 and API Spec 2W.
1.1.2
API Spec 2Y 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 quenched-and-tempered steels, users may want to consider welding consumables which avoid undermatched weld metal. Conversely, the steels should be amenable to fabrication and welding under shipyard and offshore conditions
2.2 Policy
(1) American Petroleum Institute (API) Specifications are published as aids to the procurement of standardized equipment and materials, as weak 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.
(2) The formulation and publication of API specifications are 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.
(3) 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 connections with an method, apparatus, or product covered by letter patent, nor as insuring anyone against liability for infringement of letters patent.
(4) 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 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.
Any manufacturer producing equipment or materials intended to conform to API Specification is responsible for complying with all the provisions of that Specification including all the applicable provisions of API Spec Q1, Specification for quality programs, required by the product specification. The American Petroleum Institute does not represent, warrant, or guarantee that such products of in fact conform to the applicable API standard or specification.
This specification covers the design, manufacture, and use of steel derricks, portable masts, crown black assemblies, and substructures suitable for drilling and servicing of wells. It includes stipulations for marking, inspection, standard ratings, design loading, and design specifications of the equipment . Definitions of commonly used terms are included in Section 3.
1.1 Purpose
1.1.1 The purpose of this specification is to provide suitable structures for drilling and well servicing operations and to provide a uniform method of rating the structures for the petroleum industry. It is the intent that these specifications be applied to all new designs of all standard derricks, special derricks, portable masts and substructures.
1.1.2 Products manufactured according to API Standards 4A, 4D, and 4E may not necessarily comply with all the requirements of this specification. It is the committee&#;s intention yay egos standard be written to meet the requirements of present and future operating conditions, such as deeper drilling, offshore drilling from floating devices, and the effect of earthquakes , storms, and other adverse operating conditions.
1.1.3 The standard is not a textbook, but rather a guide by which manufacturer and user will have common understanding of the capacities and ratings of the various structures for drilling and well servicing operations.
1.2 Product Specification Levels
This Specification establishes requirements for two product specification levels. These two PSL designations define different levels of technical and quality requirements. PSL 1 includes practices currently being implemented by a broad spectrum of the manufacturing industry. All the requirements of this specification are applicable to PSL 1 unless specifically identified as PSL 2. PSL 2 includes all the requirements of PSL 1 plus additional practices currently being implemented by a broad spectrum of users.
1.3 Supplementary Requirements
Supplementary requirements shall apply only when contractually specified by the Purchaser. Appendix A gives a number of standard supplementary requirements.
well-servicing operations in the petroleum industry, provides a uniform method of rating the structures, and provides two PSLs.
This specification is applicable to all new designs of all steel derricks, masts, guyed masts, substructures, and crown blocks.
Annex A provides a number of standard Supplementary Requirements (SRs) which apply only if specified by the purchaser.
This specification is applicable to all new steel derricks, masts (including masts with guy lines and service rig masts), substructures, and crown block assemblies with a date of manufacture after the effective date of this specification. Annex A provides a number of standard Supplementary Requirements (SRs) that apply only if specified by the purchaser. Annex B is an informative Annex to assist in an understanding/application of this API specification. Annex C is an informative Annex regarding the API Monogram Program and the API Monogram marking requirements. Annex D is an informative Annex providing guidelines to assist the Purchaser with purchasing equipment manufactured to the requirements in this API document.
industry, provides a uniform method of rating the structures, and provides two Product Specification Levels (PSLs).
This specification is applicable to all new steel
derricks, masts (including masts with guy lines and service rig masts), substructures, and crown block assemblies with a date of manufacture after the effective date of this specification. Annex A provides a number of standard Supplementary Requirements (SRs) that apply only if specified by the purchaser. Annex B is an informative Annex to assist in an understanding/application of this API specification. Annex C is an informative Annex regarding the API Monogram Program and the API Monogram marking requirements. Annex D is an informative Annex providing guidelines to assist the Purchaser with purchasing equipment manufactured to the requirements in this API document.
This specification is applicable to all new steel derricks, masts (including masts with guy lines and service rig masts), substructures, and crown block assemblies with a date of manufacture after the effective date of this specification. Annex A provides a number of standard Supplementary Requirements (SRs) that apply only if specified by the purchaser. Annex B is an informative Annex to assist in an understanding/application of this API specification. Annex C is an informative Annex regarding the API Monogram Program and the API Monogram marking requirements. Annex D is an informative Annex providing guidelines to assist the Purchaser with purchasing equipment manufactured to the requirements in this API document.
recommendations for suitable steel structures for drilling and well servicing operations in the petroleum industry, provides a uniform method of rating the structures, and provides two Product Specification Levels (PSLs).
This specification is applicable to all
new steel derricks, masts (including masts with guy lines and service rig masts), substructures, and crown block assemblies with a date of manufacture after the effective date of this specification. Annex A provides a number of standard Supplementary Requirements (SRs) that apply only if specified by the purchaser. Annex B is an informative Annex to assist in an understanding/application of this API specification. Annex C is an informative Annex regarding the API Monogram Program and the API Monogram marking requirements. Annex D is an informative Annex providing guidelines to assist the Purchaser with purchasing equipment manufactured to the requirements in this API document.
1.1 Coverage&#;Threading and Gauging
This specification covers dimensions, tolerances, and marking requirements for API threads and the gauges that control the acceptance criteria for the threads. Thread element gauges, instruments, and requirements for the inspection of threads for line pipe, round thread casing, round thread tubing, and buttress casing connections are included. Thread dimensions shown without specifications (or shown as NA) are not subject to inspection of diameter, ovality, and addendum. Thread dimensions shown without tolerances are related to the basis for connection design and are not subject to measurement to determine acceptance of product.
1.2 Coverage&#;Inspection
Thread inspection applies at the point of manufacture prior to shipment, to inspection at some intermediate point, to inspection subsequent to delivery at destination, and to inspection by inspectors representing the purchaser or the manufacturer. The manufacturer may, at his or her option, use other instruments or methods to control manufacturing operations; but acceptance and rejection of the product is determined by the results of inspection made in accordance with the requirements of this specification.
Thread inspection is performed using instruments designed to measure either the functional relationship of multiple thread elements or measure an individual thread element. The inspection requirements include measurements of standoff, diameter, ovality, addendum, taper, lead, height, and angle of thread that are applicable to threads having 11 or less turns per inch (0.45 or less turns per mm). Ring and plug gauges are designed to measure the functional size of an internal or external thread. Individual thread elements listed are measured with one or more specific instruments.
See API 5B1 for additional inspection procedures.
1.3 Application of the API Monogram
If product (master gauges only) 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.
1.4 Other Applications
By agreement between the purchaser and manufacturer, the supplemental requirements for Enhanced Leak Resistance LTC in API 5TRSR22 and Annex B apply.
Information on the shipping of Master Gauges can be found in Annex C.
This standard specifies the technical delivery conditions for steel pipes (casing, tubing, and pup joints), coupling stock, coupling material, and accessory material, and establishes requirements for three product specification levels (PSL-1, PSL-2, and PSL-3). The requirements for PSL-1 are the basis of this standard. The requirements that define different levels of standard technical requirements for PSL-2 and PSL-3, for all grades (except H-40, L 80 9Cr, and C110) are provided.
For pipes covered by this standard, the sizes, masses, and wall thicknesses, as well as grades and applicable endfinishes, are provided. API 5L pipe may be ordered as casing in accordance with API 5C6.
By agreement between the purchaser and manufacturer, this standard can also be applied to other plain-end pipe sizes and wall thicknesses.
1.2 Applicability&#;Connections
This standard is applicable to the following connections in accordance with API 5B:
&#; short round thread casing (SC)
&#; long round thread casing (LC)
&#; buttress thread casing (BC)
&#; non-upset tubing (NU)
&#; external upset tubing (EU)
&#; integral tubing (IJ)
For such connections, this standard specifies the technical delivery conditions for couplings and thread protection. Supplementary requirements that can optionally be agreed upon for enhanced leak resistance connections (LC) are provided.
This standard can also be applied to tubulars with connections not covered by API standards.
This standard is not applicable to threading requirements.
NOTE Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads, are given in API 5B.
1.3 Applicability&#;Grades
The products to which this standard is applicable include the following grades: H40, J55, K55, N80 (all types), L80 (all types), C90, R95, T95, P110, C110, and Q125.
1.4 Supplementary Requirements Supplementary requirements that may be specified by the purchaser or agreed between purchaser and manufacturer for non-destructive examination, fully machined coupling blanks, upset casing, electric-welded casing, tubing and pup joints, impact testing, seal-ring couplings, tensile testing, and sulfide stress cracking testing are provided.
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.
This standard specifies the technical delivery conditions for steel pipes (casing, tubing, and pup joints), coupling stock, coupling material, and accessory material, and establishes requirements for three product specification levels (PSL-1, PSL-2, and PSL-3). The requirements for PSL-1 are the basis of this standard. The requirements that define different levels of standard technical requirements for PSL-2 and PSL-3, for all grades (except H-40, L 80 9Cr, and C110) are provided.
For pipes covered by this standard, the sizes, masses, and wall thicknesses, as well as grades and applicable endfinishes, are provided. API 5L pipe may be ordered as casing in accordance with API 5C6.
By agreement between the purchaser and manufacturer, this standard can also be applied to other plain-end pipe sizes and wall thicknesses.
1.2 Applicability&#;Connections
This standard is applicable to the following connections in accordance with API 5B:
&#; short round thread casing (SC)
&#; long round thread casing (LC)
&#; buttress thread casing (BC)
&#; non-upset tubing (NU)
&#; external upset tubing (EU)
&#; integral tubing (IJ)
For such connections, this standard specifies the technical delivery conditions for couplings and thread protection. Supplementary requirements that can optionally be agreed upon for enhanced leak resistance connections (LC) are provided.
This standard can also be applied to tubulars with connections not covered by API standards.
This standard is not applicable to threading requirements.
NOTE Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads, are given in API 5B.
1.3 Applicability&#;Grades
The products to which this standard is applicable include the following grades: H40, J55, K55, N80 (all types), L80 (all types), C90, R95, T95, P110, C110, and Q125.
1.4 Supplementary Requirements Supplementary requirements that may be specified by the purchaser or agreed between purchaser and manufacturer for non-destructive examination, fully machined coupling blanks, upset casing, electric-welded casing, tubing and pup joints, impact testing, seal-ring couplings, tensile testing, and sulfide stress cracking testing are provided.
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.
1.1 Coverpage
This standard specifies the technical delivery conditions for steel pipes (casing, tubing, and pup joints), coupling stock, coupling material, and accessory material, and establishes requirements for three product specification levels (PSL-1, PSL-2, and PSL-3). The requirements for PSL-1 are the basis of this standard. The requirements that define different levels of standard technical requirements for PSL-2 and PSL-3, for all grades (except H-40, L 80 9Cr, and C110) are provided.
For pipes covered by this standard, the sizes, masses, and wall thicknesses, as well as grades and applicable end- finishes, are provided. API 5L pipe may be ordered as casing in accordance with API 5C6.
By agreement between the purchaser and manufacturer, this standard can also be applied to other plain-end pipe sizes and wall thicknesses.
&#; Group 1: All casing and tubing in Grades H, J, K, and N listed in Tables 1.1, 1.2, and 1.3
&#; Group 2: All restricted yield strength casing and tubing in Grades C and L listed in Tables 1.1 and 1.3 and other outside diameters and/or wall thickness of Grades C90 and T95 as agreed upon between the purchaser and the manufacturer.
&#; Group 3: All high strength casing and tubingGrade P listed in Tables 1.1, 1.2, and 1.3
&#; Group 4: All special service casing in Grade Q that is listed in Table 1.1 or other outside diameters and/or wall thicknesses as specified on the purchase order. Supplementary requirements for coupling blanks, upset casing, electric resistances welded casing, electric resistance welded casing, increased frequency of mechanical testing and seal ring couplings are specified in SR9, SR10, SR11, SR12, and SR13 respectively.
All requirements given herein for casing and tubing shall apply to pup joints and connectors, except as otherwise specified. Connectors are defined as a tubular section used for the purpose of 1) joining or changing from one size, weight, or type of threaded connection to the same or another size, weight, or type of threaded connection, or 2) other application
Within this Specification:
&#;Shall&#; is used to indicate that a provision is mandatory.
&#;Should&#; is used to indicate that a provision us not mandatory, but recommended as good practice.
&#;May&#; is used to indicate that a provision is optional.
Threading Requirements Dimensional requirements on threads and thread gages, stipulations on gaging practice, gage specifications and certification, as well as instruments and methods for inspections of threads are given in API Std 5B and are applicable to products covered by this specification.
1.3 Dimensional Tables In the dimensional tables herein, pipe is designated by outside diameter size. The outside diameter size of external upset pipe is the outside diameter of the body of the pipe, not the upset portion
1.4 Metric Conversions Metric Conversions of English units are provided throughout the text of this specification in parentheses, e.g., 6 in. (152,4 mm). Note use of comma instead of period for decimal point in metric values. Metric equivalents of U.s. customary values are also included in all tables and figures, except tables in Section 6 which are reproduced in the metric system Appendix A.
1.5 Referenced Standards
a. General. This specification includes by reference. Either in total or in part, other API, industry and government standard listed in table 1.4
b.Requirements. Requirements of other standards included by reference in this specification are essential to the safety and interchangeability of the equipment produced
c.Equivalent Standards. Other Nationally or internationally recognized standards shall be submitted to and approved by API for inclusion this specification prior to their use as equivalent standards.
1.1 This specification covers steel casing, tubing, and liners in the designations and wall thickness applicable to the following four groups and shown in Tables 1.1, 1.2, and 1.3. This specification also covers pup joints , connectors, couplings, and thread protection. Supplementary requirements for coupling blanks, upset Casin, electric resistance welding casing, increased frequency of mechanical testing and seal ring couplings are specified in SR9, SR10, SR11, SR12, and SR13 respectively.
&#; Group 1: All casing and tubing in Grades H, J, K, and N listed in Tables 1.1, 1.2, and 1.3
&#; Group 2: All restricted yield strength casing and tubing in Grades C and Llisted in Tables 1.1 and 1.3 and other outside diameters and/or wall thickness of Grades C90 and T95 as agreed upon between the purchaser and the manufacturer.
&#; Group 3: All high strength casing and tubing seamless Grade P listed in Tables A-1 and A-3 and all sizes 5.5 and larger electric welded (EW) Grade P listed in table A-1.
&#; Group 4: All special service casing in Grade Q that is listed in Table A-1 or other outside diameters and/or wall thicknesses as specified on the purchase order.
All requirements given herein for casing and tubing shall apply to pup joints and connectors, except as otherwise specified. Connectors are defined as a tubular section used for the purpose of 1) joining or changing from one size, weight, or type of threaded connection to the same or another size, weight, or type of threaded connection, or 2) other application
Within this Specification:
&#;Shall&#; is used to indicate that a provision is mandatory.
&#;Should&#; is used to indicate that a provision us not mandatory, but recommended as good practice.
&#;May&#; is used to indicate that a provision is optional.
Threading Requirements Dimensional requirements on threads and thread gages, stipulations on gaging practice, gage specifications and certification, as well as instruments and methods for inspections of threads are given in API Std 5B and are applicable to products covered by this specification.
1.3 Dimensional Tables. In the dimensional tables herein, pipe is designated by outside diameter size. The outside diameter size of external upset pipe is the outside diameter of the body of the pipe, not the upset portion
1.4 Metric Conversions Metric Conversions of U.S. customary units are provided throughout the text of this specification in parentheses, e.g., 6 in. (152,4 mm). Note use of comma instead of period for decimal point in metric values. Metric equivalents of U.s. customary values are also included in all tables and figures, except tables in Sections 4, 6, 8 which are reproduced in the metric system Appendix A.
1.5 Referenced Standards
a. General. This specification includes by reference. Either in total or in part, other API, industry and government standard listed in table 1.4
b.Requirements. Requirements of other standards included by reference in this specification are essential to the safety and interchangeability of the equipment produced
c.Equivalent Standards. Other Nationally or internationally recognized standards shall be submitted to and approved by API for inclusion this specification prior to their use as equivalent standards.
1.6Retention of Records. Tests and inspections requiring retention of records in this specification are shown in Table 1.5 such records shall be retained by the manufacturer and shall be available to the purchaser on request for a period of three years after the date of purchase from the manufacturer.
1.7 Measuring Devices. If measuring equipment, whose calibration or verification is required under the provisions of the specification, is subjected to unusual severe conditions such as would make its accuracy questionable, recalibration or revivification shall be performed before further use of equipment.
1.8 Special Processes are the final operations which are performed during pip manufacturing that affect attribute compliance required in this document (except chemistry and dimensions).
1.9 Certification. The manufacturer shall, upon request by the purchaser, furnish to the purchaser a certificate of compliance stating that the material has been manufactured, sampled, tested and inspected in accordance with this specification and has been found to meet the requirements
Where additional information is required, including the results of mechanical testing. SR15 shall be specified in the purchase order.
&#; Group 1: All casing and tubing in Grades H, J, K, and N listed in Tables 1.1, 1.2, and 1.3
&#; Group 2: All restricted yield strength casing and tubing in Grades C, L, and T listed in Tables 1.1 and 1.3 and other outside diameters and/or wall thickness of Grades C90 and T95 as agreed upon between the purchaser and the manufacturer.
&#; Group 3: All high strength casing and tubing seamless Grade P listed in Tables A-1 and A-3 and all sizes 5.5 and larger electric welded (EW) Grade P listed in table A-1.
&#; Group 4: All special service casing in Grade Q that is listed in Table A-1 or other outside diameters and/or wall thicknesses as specified on the purchase order.
All requirements given herein for casing and tubing shall apply to pup joints and connectors, except as otherwise specified. Connectors are defined as a tubular section used for the purpose of 1) joining or changing from one size, weight, or type of threaded connection to the same or another size, weight, or type of threaded connection, or 2) other application
Within this Specification:
&#;Shall&#; is used to indicate that a provision is mandatory.
&#;Should&#; is used to indicate that a provision us not mandatory, but recommended as good practice.
&#;May&#; is used to indicate that a provision is optional.
Threading Requirements Dimensional requirements on threads and thread gages, stipulations on gaging practice, gage specifications and certification, as well as instruments and methods for inspections of threads are given in API Std 5B and are applicable to products covered by this specification.
1.3 Dimensional Tables. In the dimensional tables herein, pipe is designated by outside diameter size. The outside diameter size of external upset pipe is the outside diameter of the body of the pipe, not the upset portion
1.4 Metric Conversions Metric Conversions of U.S. customary units are provided throughout the text of this specification in parentheses, e.g., 6 in. (152,4 mm). Note use of comma instead of period for decimal point in metric values. Metric equivalents of U.s. customary values are also included in all tables and figures, except tables in Sections 4, 6, 8 which are reproduced in the metric system Appendix A.
1.5 Referenced Standards
a. General. This specification includes by reference. Either in total or in part, other API, industry and government standard listed in table 1.4
b.Requirements. Requirements of other standards included by reference in this specification are essential to the safety and interchangeability of the equipment produced
c.Equivalent Standards. Other Nationally or internationally recognized standards shall be submitted to and approved by API for inclusion this specification prior to their use as equivalent standards.
1.6 Retention of Records. Tests and inspections requiring retention of records in this specification are shown in Table 1.5 such records shall be retained by the manufacturer and shall be available to the purchaser on request for a period of three years after the date of purchase from the manufacturer.
1.7 Measuring Devices. If measuring equipment, whose calibration or verification is required under the provisions of the specification, is subjected to unusual severe conditions such as would make its accuracy questionable, recalibration or revivification shall be performed before further use of equipment.
1.8 Special Processes are the final operations which are performed during pip manufacturing that affect attribute compliance required in this document (except chemistry and dimensions).
1.9 Certification. The manufacturer shall, upon request by the purchaser, furnish to the purchaser a certificate of compliance stating that the material has been manufactured, sampled, tested and inspected in accordance with this specification and has been found to meet the requirements
Where additional information is required, including the results of mechanical testing. SR15 shall be specified in the purchase order.
&#; Group 1: All casing and tubing in Grades H, J, K, and N listed in Tables 1.1, 1.2, and 1.3
&#; Group 2: All restricted yield strength casing and tubing in Grades C, L, and T listed in Tables 1.1 and 1.3 and other outside diameters and/or wall thickness of Grades C90 and T95 as agreed upon between the purchaser and the manufacturer.
&#; Group 3: All high strength casing and tubing seamless Grade P listed in Tables 1.1 and 1.3 and all sizes 5.5 and larger electric welded (EW) Grade P listed in table 1.1.
&#; Group 4: All special service casing in Grade Q that is listed in Table 1.1 or other outside diameters and/or wall thicknesses as specified on the purchase order.
All requirements given herein for casing and tubing shall apply to pup joints and connectors, except as otherwise specified. Connectors are defined as a tubular section used for the purpose of 1) joining or changing from one size, weight, or type of threaded connection to the same or another size, weight, or type of threaded connection, or 2) other application
In developing an order for products made to this specification, the user should refer to Suggestion for Ordering API Casing/Tubing to properly define specific requirements.
Within this Specification:
&#;Shall&#; is used to indicate that a provision is mandatory.
&#;Should&#; is used to indicate that a provision us not mandatory, but recommended as good practice.
&#;May&#; is used to indicate that a provision is optional.
Threading Requirements Dimensional requirements on threads and thread gages, stipulations on gaging practice, gage specifications and certification, as well as instruments and methods for inspections of threads are given in API Std 5B and are applicable to products covered by this specification.
1.3 In the dimensional tables herein, pipe is designated by outside diameter size. The outside diameter size of external upset pipe is the outside diameter of the body of the pipe, not the upset portion
1.4 Metric Conversions Metric Conversions of U.S. customary units are provided in the metric version of this specification. Note use of comma instead of period for decimal point in metric values. The procedures which were used to make this conversation are shown in Appendix M
1.5 Referenced Standards
a. General. This specification includes by reference. Either in total or in part, other API, industry and government standard listed in table 1.4
b. Requirements. Requirements of other standards included by reference in this specification are essential to the safety and interchangeability of the equipment produced
c. Equivalent Standards. Other Nationally or internationally recognized standards shall be submitted to and approved by API for inclusion this specification prior to their use as equivalent standards.
1.6 Retention of Records. Tests and inspections requiring retention of records in this specification are shown in Table 1.5 such records shall be retained by the manufacturer and shall be available to the purchaser on request for a period of three years after the date of purchase from the manufacturer.
1.7 Test Equipment. If test equipment, whose calibration pr verification is required under the provisions of the specification, is subjected to unusual or severe conditions such as would make its accuracy questionable, recalibration or revivification shall be performed before further use of the equipment.
&#; Group 1: All casing and tubing in Grades H, J, K, and N listed in Tables A-1, A-2, and A-3
&#; Group 2: All restricted yield strength casing and tubing in Grades C, L, and T listed in Tables A-1 and A-3 and other outside diameters and/or wall thickness of Grades C90 and T95 as agreed upon between the purchaser and the manufacturer.
&#; Group 3: All high strength casing and tubing in seamless Grade P listed in Tables A-1 and A-3 and all sizes 5.5 and larger electric welded (EW) Grade P listed in table A-1.
&#; Group 4: All special service casing in Grade Q that is listed in Table A-1 or other outside diameters and/or wall thicknesses as specified on the purchase order.
All requirements given herein for casing and tubing shall apply to pup joints and connectors, except as otherwise specified.
In developing an order for products made to this specification, the user should refer to Section 4 to properly define specific requirements.
1.2 Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads are given in API Standard 5B and are applicable to products covered by this specification.
1.3 In the dimensional tables herein, pipe is designated by outside diameter size. The outside diameter size of external upset pipe is the outside diameter of the body of the pipe, not the upset portion
1.4 Metric Conversions of U.S. customary units are provided in the metric version of this specification.
&#; Group 1: All casing and tubing in Grades H, J, K, M and N listed in Tables A-1, A-2, and A-3
&#; Group 2: All restricted yield strength casing and tubing in Grades C, L, and T listed in Tables A-1 and A-3 and other outside diameters and/or wall thickness of Grades C90 and T95 as agreed upon between the purchaser and the manufacturer.
&#; Group 3: All casing and tubing in Grade P listed in Tables A-1 and A-3
&#; Group 4: All casing in Grade Q that is listed in Table A-1 or other outside diameters and/or wall thicknesses as specified on the purchase order.
All requirements given herein for casing and tubing shall apply to pup joints and connectors, except as otherwise specified.
In developing an order for products made to this specification, the user should refer to Section 4 to properly define specific requirements.
1.2NOTE Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads are given in API Standard 5B and are applicable to products covered by this specification.
1.3 In the dimensional tables herein, pipe is designated by outside diameter size. The outside diameter size of external upset pipe is the outside diameter of the body of the pipe, not the upset portion
1.4 Metric Conversions of U.S. customary units are provided in the metric version of this specification.
1.1 This specification covers steel casing, tubing, and liners in the designations and wall thickness applicable to the following four groups and shown in Tables A-1, A-2, and A-3 of Appendix A. This specification also covers pup joints , connectors, couplings, and thread protection. Supplementary requirements are specified in in appendix B.
&#; Group 1: All casing and tubing in Grades H, J, K, M and N listed in Tables A-1, A-2, and A-3
&#; Group 2: All restricted yield strength casing and tubing in Grades C, L, and T listed in Tables A-1 and A-3 and other outside diameters and/or wall thickness of Grades C90 and T95 as agreed upon between the purchaser and the manufacturer.
&#; Group 3: All casing and tubing in Grade P listed in Tables A-1 and A-3
&#; Group 4: All casing in Grade Q that is listed in Table A-1 or other outside diameters and/or wall thicknesses as specified on the purchase order.
All requirements given herein for casing and tubing shall apply to pup joints and connectors, except as otherwise specified.
In developing an order for products made to this specification, the user should refer to Section 4 to properly define specific requirements.
1.2NOTE Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads are given in API Standard 5B and are applicable to products covered by this specification.
1.3 In the dimensional tables herein, pipe is designated by outside diameter size. The outside diameter size of external upset pipe is the outside diameter of the body of the pipe, not the upset portion
1.4 Metric Conversions of U.S. customary units are provided in the metric version of this specification.
&#; short round thread casing (STC);
&#; long round thread casing (LC);
&#; buttress thread casing (BC);
extreme line casing (XC);
&#; non-upset tubing (NU); &#; external upset tubing (EU); &#; integral tubing connections (IJ). For such connections, this International standard specifies the technical delivery conditions and thread protection
This international can also be applied to tubulars with connections not covered by ISO/API standards. This Standard can also be applied to tubulars with connections not covered by API standards. 1.2 The four groups of products to which this Standard is applicable include the following grades of pipe: &#; Group 1: All casing and tubing in Grades H, J, K, N and R; &#; Group 2: All casing and tubing in Grades C, L, M and T; &#; Group 3: All casing and tubing in Grade P; &#; Group 4: All casing in Grade Q. 1.3 Casing sizes larger than Label 1: 4-1/2 but smaller than Label 1: 10-3/4 can be specified by the purchaser to be used in tubing service, see Tables C.1, C.24, C.30 and C.3.1 or Tables E.1, E.24, E..30 and E.31. 1.4 Supplementary requirements that can optionally be agreed between purchaser and manufacturer for nondestructive examination, fully machined coupling blanks, upset casing, electric-welded casing, tubing and pup joints, impact testing, seal ring couplings, test certificates, tensile testing and sulfide stress cracking testing are given in Annex A. 1.5This International Standard is not applicable to threading requirements. NOTE Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads are given in API Standard 5B and are applicable to products covered by this specification.
http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/718aae92-3a4b-47ba-9b37-fd1f31d9abbd.htm 01-Oct-01 API SPEC 5CT 8TH ED () Specification for Casing and Tubing; Eighth Edition 1.1 This Standard specifies the technical delivery conditions for steel pipes (casing, tubing and pup joints), coupling stock, coupling material and accessory material and establishes requirements for three Product Specification Levels (PSL-1, PSL-2, PSL-3). The requirements for PSL-1 are the basis of this Standard. The requirements that define different levels of standard technical requirements for PSL-2 and PSL-3, for all Grades except H-40, L-80 9Cr and C110, are contained in Annex H.For pipes covered by this Standard, the sizes, masses and wall thicknesses as well as grades and applicable end finishes are listed in Tables C.1 and C.2 and Tables E.1 and E.2.
By agreement between the purchaser and manufacturer, this Standard can also be applied to other plain-end pipe sizes and wall thicknesses.
This Standard is applicable to the following connections in accordance with API Spec 5B:
&#; short round thread casing (SC);
&#; long round thread casing (LC);
&#; buttress thread casing (BC);
extreme line casing (XC);
&#; non-upset tubing (NU); &#; external upset tubing (EU); &#; integral tubing connections (IJ). For such connections, this Standard specifies the technical delivery conditions for couplings and thread protection. Supplementary requirements that can optionally be agreed for enhanced leak resistance connections (LC) are given in A.11 SR22. This international can also be applied to tubulars with connections not covered by ISO/API standards. This Standard can also be applied to tubulars with connections not covered by API standards. 1.2 The four groups of products to which this Standard is applicable include the following grades of pipe: &#; Group 1: All casing and tubing in Grades H, J, K, N and R; &#; Group 2: All casing and tubing in Grades C, L, M and T; &#; Group 3: All casing and tubing in Grade P; &#; Group 4: All casing in Grade Q. 1.3 Casing sizes larger than Label 1: 4-1/2 but smaller than Label 1: 10-3/4 can be specified by the purchaser to be used in tubing service, see Tables C.1, C.23, C.27 and C.28 or Tables E.1, E.23, E.27 and E.28. 1.4 Supplementary requirements that can optionally be agreed between purchaser and manufacturer for nondestructive examination, fully machined coupling blanks, upset casing, electric-welded casing, tubing and pup joints, impact testing, seal ring couplings, test certificates, tensile testing and sulfide stress cracking testing are given in Annex A. 1.5 This Standard is not applicable to threading requirements. NOTE: Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads are given in API Spec 5B.
http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/d86ba73e--436c-88d0-7ea1ca8b3a33.htm 01-Jun-06 API SPEC 5CT 9TH ED () Specification for Casing and Tubing; Ninth Edition; Effective Date: January 1, 1 Scope1.1 This Standard specifies the technical delivery conditions for steel pipes (casing, tubing and pup joints), coupling stock, coupling material and accessory material and establishes requirements for three Product Specification Levels (PSL-1, PSL-2, PSL-3). The requirements for PSL-1 are the basis of this Standard. The requirements that define different levels of standard technical requirements for PSL-2 and PSL-3, for all Grades except H-40, L-80 9Cr and C110, are contained in Annex H.
For pipes covered by this Standard, the sizes, masses and wall thicknesses as well as grades and applicable end finishes are listed in Tables C.1 and C.2 and Tables E.1 and E.2.
By agreement between the purchaser and manufacturer, this Standard can also be applied to other plain-end pipe sizes and wall thicknesses.
This Standard is applicable to the following connections in accordance with API Spec 5B:
&#; short round thread casing (SC);
&#; long round thread casing (LC);
&#; buttress thread casing (BC);
&#; non-upset tubing (NU);
&#; external upset tubing (EU);
&#; integral tubing connections (IJ).
For such connections, this Standard specifies the technical delivery conditions for couplings and thread protection. Supplementary requirements that can optionally be agreed for enhanced leak resistance connections (LC) are given in A.11 SR22.
This Standard can also be applied to tubulars with connections not covered by API standards.
1.2 The four groups of products to which this Standard is applicable include the following grades of pipe:
&#; Group 1: All casing and tubing in Grades H, J, K, N and R;
&#; Group 2: All casing and tubing in Grades C, L, M and T;
&#; Group 3: All casing and tubing in Grade P;
&#; Group 4: All casing in Grade Q.
1.3 Casing sizes larger than Label 1: 4-1/2 but smaller than Label 1: 10-3/4 can be specified by the purchaser to be used in tubing service, see Tables C.1, C.23, C.27 and C.28 or Tables E.1, E.23, E.27 and E.28.
1.4 Supplementary requirements that can optionally be agreed between purchaser and manufacturer for nondestructive examination, fully machined coupling blanks, upset casing, electric-welded casing, tubing and pup joints, impact testing, seal ring couplings, test certificates, tensile testing and sulfide stress cracking testing are given in Annex A.
1.5This Standard is not applicable to threading requirements.
NOTE Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads are given in API Spec 5B.
For pipes covered by this Standard, the sizes, masses and wall thicknesses as well as grades and applicable end finishes are listed in Tables C.1 and C.2 and Tables E.1 and E.2.
By agreement between the purchaser and manufacturer, this Standard can also be applied to other plain-end pipe sizes and wall thicknesses.
This Standard is applicable to the following connections in accordance with API Spec 5B:
&#; short round thread casing (SC);
&#; long round thread casing (LC);
&#; buttress thread casing (BC);
&#; non-upset tubing (NU);
&#; external upset tubing (EU);
&#; integral tubing connections (IJ).
For such connections, this Standard specifies the technical delivery conditions for couplings and thread protection. Supplementary requirements that can optionally be agreed for enhanced leak resistance connections (LC) are given in A.11 SR22.
This Standard can also be applied to tubulars with connections not covered by API standards.
1.2 The four groups of products to which this Standard is applicable include the following grades of pipe:
&#; Group 1: All casing and tubing in Grades H, J, K, N and R;
&#; Group 2: All casing and tubing in Grades C, L, M and T;
&#; Group 3: All casing and tubing in Grade P;
&#; Group 4: All casing in Grade Q.
1.3 Casing sizes larger than Label 1: 4-1/2 but smaller than Label 1: 10-3/4 can be specified by the purchaser to be used in tubing service, see Tables C.1, C.23, C.27 and C.28 or Tables E.1, E.23, E.27 and E.28.
1.4 Supplementary requirements that can optionally be agreed between purchaser and manufacturer for nondestructive examination, fully machined coupling blanks, upset casing, electric-welded casing, tubing and pup joints, impact testing, seal ring couplings, test certificates, tensile testing and sulfide stress cracking testing are given in Annex A.
1.5 This Standard is not applicable to threading requirements.
NOTE Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads are given in API Spec 5B.
For pipes covered by this Standard, the sizes, masses and wall thicknesses as well as grades and applicable end finishes are listed in Tables C.1 and C.2 and Tables E.1 and E.2.
By agreement between the purchaser and manufacturer, this Standard can also be applied to other plain-end pipe sizes and wall thicknesses.
This Standard is applicable to the following connections in accordance with API Spec 5B:
&#; short round thread casing (SC);
&#; long round thread casing (LC);
&#; buttress thread casing (BC);
&#; non-upset tubing (NU);
&#; external upset tubing (EU);
&#; integral tubing connections (IJ).
For such connections, this Standard specifies the technical delivery conditions for couplings and thread protection. Supplementary requirements that can optionally be agreed for enhanced leak resistance connections (LC) are given in A.11 SR22.
This Standard can also be applied to tubulars with connections not covered by API standards.
1.2 The four groups of products to which this Standard is applicable include the following grades of pipe:
&#; Group 1: All casing and tubing in Grades H, J, K, N and R;
&#; Group 2: All casing and tubing in Grades C, L, M and T;
&#; Group 3: All casing and tubing in Grade P;
&#; Group 4: All casing in Grade Q.
1.3 Casing sizes larger than Label 1: 4-1/2 but smaller than Label 1: 10-3/4 can be specified by the purchaser to be used in tubing service, see Tables C.1, C.23, C.27 and C.28 or Tables E.1, E.23, E.27 and E.28.
1.4 Supplementary requirements that can optionally be agreed between purchaser and manufacturer for nondestructive examination, fully machined coupling blanks, upset casing, electric-welded casing, tubing and pup joints, impact testing, seal ring couplings, test certificates, tensile testing and sulfide stress cracking testing are given in Annex A.
1.5 This Standard is not applicable to threading requirements.
NOTE Dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications, as well as instruments and methods for inspection of threads are given in API Spec 5B.
Special notice: Fittings for use with Line Pipe should preferably be threaded in accordance with these specifications. When fittings with the shorter commercial standard are to be used on line pipe (both API and Commercial Standard have the same pitch diameter) care should be exercised that there is no interference or shoulder on the inside threaded portion of the fitting to prevent the projection of the longer Line Pipe thread beyond the end of the commercial standard thread in the fitting.
Material Covered
1. These specification apply to welded and seamless steel, and welded iron tubular good for line pipe purposes, commonly used to convey gas, water, or oil.
Special notice: Fittings for use with Line Pipe should preferably be threaded in accordance with these specifications. When fittings with the shorter commercial standard are to be used on line pipe (both API and Commercial Standard have the same pitch diameter) care should be exercised that there is no interference or shoulder on the inside threaded portion of the fitting to prevent the projection of the longer Line Pipe thread beyond the end of the commercial standard thread in the fitting.
Material Covered
1. These specification apply to welded and seamless steel and welded iron tubular goods for line pipe purposes, commonly used to convey gas, water, or oil.
Special notice: Fittings for use with Line Pipe should preferably be threaded in accordance with these specifications. When fittings with the shorter commercial standard are to be used on line pipe (both API and Commercial Standard have the same pitch diameter) care should be exercised that there is no interference or shoulder on the inside threaded portion of the fitting to prevent the projection of the longer Line Pipe thread beyond the end of the commercial standard thread in the fitting.
Material Covered
1. These specification apply to welded wrought iron tubular goods for line pipe purposes, commonly used to convey gas, water, or oil, and include light weight, standard and extra strong classes.
The purpose of this specification is to provide standards for pipe suitable for use in conveying gas, water, and oil in both the oil and natural gas industries.
specification levels (PSL 1 and PSL 2) of seamless and welded steel pipes for use in pipeline transportation systems in the petroleum and natural gas industries.
This Standard is not applicable to cast pipe.
specification levels (PSL 1 and PSL 2) of seamless and welded steel pipes for use in pipeline transportation systems in the petroleum and natural gas industries.
This Standard is not applicable to cast pipe.
This specification provides requirements for the manufacture of two product specification levels (PSL 1 and PSL 2) of seamless and welded steel pipe for use in pipeline transportation systems in the petroleum and natural gas industries.
This specification is not applicable to cast pipe.
1.2 Application of the API Monogram
If the product is manufactured at a facility licensed by the American Petroleum Institute (API) and is intended to be supplied bearing the API Monogram, the requirements of Annex A apply.
This specification is not applicable to cast pipe.
Special notice: Fittings for use with Line Pipe should preferably be threaded in accordance with these specifications. When fittings with the shorter commercial standard are to be used on line pipe (both API and Commercial Standard have the same pitch diameter) care should be exercised that there is no interference or shoulder on the inside threaded portion of the fitting to prevent the projection of the longer Line Pipe thread beyond the end of the commercial standard thread in the fitting.
Material Covered
1. These specification apply to welded wrought iron tubular goods for line pipe purposes, commonly used to convey gas, water, or oil, and include light weight, standard and extra strong classes.
Special notice: Fittings for use with Line Pipe should preferably be threaded in accordance with these specifications. When fittings with the shorter commercial standard are to be used on line pipe (both API and Commercial Standard have the same pitch diameter) care should be exercised that there is no interference or shoulder on the inside threaded portion of the fitting to prevent the projection of the longer Line Pipe thread beyond the end of the commercial standard thread in the fitting.
Material Covered
1. These specification apply to welded wrought iron tubular goods for line pipe purposes, commonly used to convey gas, water, or oil, and include light weight, standard and extra strong classes.
welded alloy line pipe with improved corrosion resistant properties. The primary product is beveled pipe. If plain-end square cut or other special end preparation is desired, this shall be subject to agreement between the purchaser and manufacturer. Included are NPS: 1 in. through 42 in.
Grades covered by this specification are:
LC30-
LC52-
LC65-
LC65-
LC30-
Within this Specification:
&#;Shall&#; is used to indicate that a provision is mandatory.
&#;Should&#; is used to indicate that a provision us not mandatory, but recommended as good practice.
&#;May&#; is used to indicate that a provision is optional.
a. This specification is under the jurisdiction of the Committee on Standardization of Tubular Goods.
b. The purpose of this specification is to provide standards for pipe with improved corrosion resistance suitable for use in conveying gas, water, and oil in both the oil and natural gas industries.
c. Although the plain-end line pipe meeting this specification is primarily intended for field makeup by circumferential welding, the manufacturer will not assume responsibility for field welding.
d. The size designations are nominal pipe sizes. In the text paragraphs herein, where pipe size limits (or size ranges) are given, these are outside-diameter sizes except where stated to be nominal. These outside-diameter size limits and ranges apply also to the corresponding nominal sizes.
1.2 Metric Units
Metric units in this specification are shown in italic type in parentheses in the text and in many tables. Outside diameters air wall thicknesses are converted from inch dimensions. The converted diameters are rounded to the nearest 0.1 mm for diameters less than 18 in. and to the nearest 1.0 mm for diameters 18 in. and larger. Wall thicknesses are rounded to the nearest 0.1 mm.
Metric inside diameters are calculated from the metric outside diameters and wall thicknesses and rounded to the nearest 0.1 mm.
Metric plain-end weights are included from the metric outside diameters and wall thicknesses using the formula in 7.1 and rounded to the nearest 0.01 kg/M.
Metric hydrostatic pressures are calculated from metric outside diameters and wall thicknesses and metric fiber stresses shown in Sect. 6.
Referenced Standards
a. General This specification includes by reference either in total or in part, other API, industry and government standards listed in Table 1.1.
b. Requirements. Requirements of other standards included by reference in this specification are essential to the safety and interchangeability of the equipment produced.
c. Equivalent Standards Other nationally or internationally recognized standards shall be submitted to and approved by API for inclusion in this specification prior to their use as equivalent standards.
welded alloy line pipe with improved corrosion resistant properties. The primary product is beveled pipe. If plain-end square cut or other special end preparation is desired, this shall be subject to agreement between the purchaser and manufacturer. Included are NPS: 1 in. through 42 in.
Grades covered by this specification are:
LC30-
LC52-
LC65-
LC65-
LC30-
Within this Specification:
&#;Shall&#; is used to indicate that a provision is mandatory.
&#;Should&#; is used to indicate that a provision us not mandatory, but recommended as good practice.
&#;May&#; is used to indicate that a provision is optional.
a. This specification is under the jurisdiction of the Committee on Standardization of Tubular Goods.
b. The purpose of this specification is to provide standards for pipe with improved corrosion resistance suitable for use in conveying gas, water, and oil in both the oil and natural gas industries.
c. Although the plain-end line pipe meeting this specification is primarily intended for field makeup by circumferential welding, the manufacturer will not assume responsibility for field welding.
d. The size designations are nominal pipe sizes. In the text paragraphs herein, where pipe size limits (or size ranges) are given, these are outside-diameter sizes except where stated to be nominal. These outside-diameter size limits and ranges apply also to the corresponding nominal sizes.
1.2 Metric Units
Metric units in this specification are shown in italic type in parentheses in the text and in many tables. Outside diameters air wall thicknesses are converted from inch dimensions. The converted diameters are rounded to the nearest 0.1 mm for diameters less than 18 in. and to the nearest 1.0 mm for diameters 18 in. and larger. Wall thicknesses are rounded to the nearest 0.1 mm.
Metric inside diameters are calculated from the metric outside diameters and wall thicknesses and rounded to the nearest 0.1 mm.
Metric plain-end weights are included from the metric outside diameters and wall thicknesses using the formula in 7.1 and rounded to the nearest 0.01 kg/M.
Metric hydrostatic pressures are calculated from metric outside diameters and wall thicknesses and metric fiber stresses shown in Sect. 6.
Referenced Standards
a. General This specification includes by reference either in total or in part, other API, industry and government standards listed in Table 1.1.
b. Requirements. Requirements of other standards included by reference in this specification are essential to the safety and interchangeability of the equipment produced.
c. Equivalent Standards Other nationally or internationally recognized standards shall be submitted to and approved by API for inclusion in this specification prior to their use as equivalent standards.
1.4 Retention of records Tests and inspections requiring retention of records in this specification shown in Table 1.2. Such records in this specification shall be retained by the manufacturer and shall be made available to the purchaser upon request for a period of three years after the date of purchase from the manufacturer. (See table 1.2 on PDF for Retention of Records)
1.5 Measuring Devices
If test or measuring equipment, whose calibration or verification is required under the provisions of the specification, is subjected to unusual questionable, recalibration or re-verification shall be performed before further use of the equipment.
1.6 Special Processes
Special processes are the final operations which are performed during pipe manufacturing that affect attribute compliance required in this document (except chemistry and dimensions). The applicable special processes are: (Refer to table under 1.6 on PDF)
1.5 Certification
The manufacturer shall, upon request by the purchaser, furnish to the purchaser a certificate of compliance stating that the material has been manufactured, sampled, tested, and inspected in accordance with this specification and has been found to meet the requirements.
Where additional information is required, including the results of mechanical testing, SR15 (Appendix D) shall be specified on the purchase order.
This specification covers seamless, centrifugal cast, and welded alloy line pipe with improved corrosion resistant properties. The primary product is beveled pipe. If plain-end square cut or other special end preparation is desired, this shall be subject to agreement between the purchaser and manufacturer. Included are NPS: 1 in. through 42 in.
Grades covered by this specification are:
LC30-
LC52-
LC65-
LC65-
LC30-
a. This specification is under the jurisdiction of the Committee on Standardization of Tubular Goods.
b. The purpose of this specification is to provide standards for pipe with improved corrosion resistance suitable for use in conveying gas, water, and oil in both the oil and natural gas industries.
c. Although the plain-end line pipe meeting this specification is primarily intended for field makeup by circumferential welding, the manufacturer will not assume responsibility for field welding.
d. The size designations are nominal pipe sizes. In the text paragraphs herein, where pipe size limits (or size ranges) are given, these are outside-diameter sizes except where stated to be nominal. These outside-diameter size limits and ranges apply also to the corresponding nominal sizes.
1.2 Metric Units
Metric units in this specification are shown in italic type in parentheses in the text and in many tables. Outside diameters air wall thicknesses are converted from inch dimensions. The converted diameters are rounded to the nearest 0.1 mm for diameters less than 18 in. and to the nearest 1.0 mm for diameters 18 in. and larger. Wall thicknesses are rounded to the nearest 0.1 mm.
Metric inside diameters are calculated from the metric outside diameters and wall thicknesses and rounded to the nearest 0.1 mm.
Metric plain-end weights are included from the metric outside diameters and wall thicknesses using the formula in 10.1 and rounded to the nearest 0.01 kg/M.
Metric hydrostatic pressures are calculated from metric outside diameters and wall thicknesses and metric fiber stresses shown in Sect. 9.
1.3 Measuring Devices
If test or measuring equipment, whose calibration or verification is required under the provisions of the specification, is subjected to unusual questionable, recalibration or re-verification shall be performed before further use of the equipment.
1.4 Special Processes
Special processes are the final operations which are performed during pipe manufacturing that affect attribute compliance required in this document (except chemistry and dimensions). The applicable special processes are: (Refer to table 1.4 on PDF)
1.5 Certification
The manufacturer shall, upon request by the purchaser, furnish to the purchaser a certificate of compliance stating that the material has been manufactured, sampled, tested, and inspected in accordance with this specification and has been found to meet the requirements.
Where additional information is required, including the results of mechanical testing, SR15 (Appendix D) shall be specified on the purchase order.
A Material Test Report, Certificate of Compliance or similar document printed from or used in electronic form from an electronic data interchange (EDI) transmission shall be regarded as having the same validity as a counterpart printed in the certifier&#;s facility. The content of the EDI transmitted document must meet the requirements of this specification and conform to any existing EDI agreement between the purchaser and the supplier.
This specification covers seamless, centrifugal cast,and welded alloy line pipe with improved corrosion resistant properties. The purpose of this specification is to provide standards for pipe with improved corrosion resistance suitable for use in conveying gas, water, and oil in both the oil and natural gas industries.
The size designations are nominal pipe sizes (NPS). In the text paragraphs herein, where pipe size limits (or size ranges) are given, these are outside diameter sizes except where stated to be nominal. These outside diameter size limits and ranges apply also to the corresponding nominal sizes. The primary product is beveled pipe. If plain-end square cut or other special end preparation is desired, this shall be subject to agreement between the purchaser and manufacturer. Included are NPS 1 in. through 42 in. Grades covered by this specification are LC30-, LC52-, LC65-, LC65-, LC30-, and LC80- 1.
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.
This specification covers seamless, centrifugal cast, and welded alloy line pipe with improved corrosion resistant properties. The purpose of this specification is to provide standards for pipe with improved corrosion resistance suitable for use in conveying gas, water, and oil in both the oil and natural gas industries. The size designations are nominal pipe sizes (NPS). In the text paragraphs herein, where pipe size limits (or size ranges) are given, these are outside diameter sizes except where stated to be nominal. These outside diameter size limits and ranges apply also to the corresponding nominal sizes. The primary product is beveled pipe. If plain-end square cut or other special end reparation is desired, this shall be subject to agreement between the purchaser and manufacturer. Included is NPS 1 in. through 42 in. Grades covered by this specification are LC30-, LC52-, LC65-, LC65-, LC30-, and LC80-.
This specification covers welded steel continuously milled pipe in the size range 0.5 in. (12.7 mm) to 6.625 in. (168.3 mm). Pipe that is pipe-to-pipe welded outside the confines of the manufacturing plant is not included within this document.
1.2 Grades covered by this specification are X52C, X56C, X60C, X65C, X70C, and X80C.
Note: Grade designations used herein are composed of the letter X followed by the Þrst two digits of the specified minimum yield strength in U.S. Customary units, and the letter C to indicate coiled pipe.
1.3 Pipe manufactured as Grade X60C or higher shall not be substituted for pipe ordered for Grade X52C or lower without purchaser approval.
1.4 Although the plain-end coiled line pipe meeting this specification is intended to be suitable for field welding, the manufacturer will not assume responsibility for field welding.
1.5 The size designations used herein are outside-diameter sizes. Pipe sizes 2 3/8 and larger are expressed as integers and fractions; pipe sizes smaller than 2 3/8 are expressed to three decimal places.
1.6 U.S. Customary units are used in this specification; SI (metric) units are shown in parentheses in the text and in many tables. See Appendix M for specific information about conversion factors and rounding procedures.
1.7 The suitability of these products for use in environments containing hydrogen sulfide is outside of the scope of this document.
The purpose of this Specification is to provide standards for pipe suitable for use in conveying gas, water, and oil in both the oil and natural gas industries. This Specification covers welded steel continuously milled coiled line pipe in the size range 0.5 in. (12.7 mm) to 6.625 in. (168.3 mm). Pipe that is pipe-to-pipe welded outside the confines of the manufacturing plant is not included within this document.
1.2
Grades covered by this specification are X52C, X56C, X60C, X65C, X70C, X80C, and X90C. Grades shall not be mixed within a milled length, or a spool. Note: Grade designations used herein are composed of the letter X followed by the first two digits of the specified minimum yield strength in U.S. customary units, and the letter C is added to indicate coiled pipe.
1.3
Pipe manufactured as Grade X60C or higher shall not be substituted for pipe ordered for Grade X52C without purchaser approval.
1.4
Although the coiled line pipe meeting this specification is intended to be suitable for field welding, the manufacturer will not assume responsibility for field welding.
1.5
The size designations used herein are outside-diameter sizes. Pipe sizes 2-3/8 and larger are expressed as integers and fractions; pipe sizes smaller than 2-3/8 are expressed to three decimal places.
1.6
US customary units are used in this specification; SI (metric) units are shown in parentheses in the text and in many tables. See Appendix M for specific information about conversion factors and rounding procedures.
1.7
The suitability of these products for use in environments containing hydrogen sulphide is outside of the scope of this document.
The primary product has square ends, but other special end preparation may be furnished by agreement between the purchaser and manufacturer. Included are NPS: 1 in. through 42 in.
Grades of base metal covered by this specification are X42, X46, X52, X56, X60, X65, X70 and X80 and grades intermediate to these. Grades of the CRA layer are LC , , , , and and other grades which are subject to agreement between the purchaser and the manufacturer.
1.2 GENERAL
a. This specification is under the jurisdiction of the Committee on Standardization of Tubular Goods.
b. The purpose of this specification is to provide standards for pipe with improved corrosion resistance suitable for use in conveying gas, water, and oil in both the oil and natural gas industries.
c. Although the plain-end line pipe meeting this specification is primarily intended for field makeup by circumferential welding, the manufacturer will not assume responsibility for field welding.
d. The size designations are nominal pipe sizes. In the text paragraphs herein, where pipe size limits (or size ranges) are given, these are outside-diameter sizes except where stated to be nominal. These outside-diameter size limits and ranges apply also to the corresponding nominal sizes.
1.3 METRIC UNITSWithin this specification a) CRA Layer is a general term referring to any internal corrosion resistant alloy layer b) Clad refers to a metallurgically bonded CRA layer. c) Lined refers to a mechanically bonded CRA layer d) &#;Shall&#; is used to indicate that a provision is mandatory. e) &#;Should&#; is used to indicate that a provision us not mandatory, but recommended as good practice. f) &#;May&#; is used to indicate that a provision is optional. 1.2 Metric Units Metric units in this specification are shown in parentheses in the text and in many tables. Outside diameters and wall thicknesses are converted from inch dimensions. The converted diameters are rounded to the nearest 0.1 mm for diameters less than 18 in., and to the nearest 1.0 mm for diameters 18 in. and larger. Wall thicknesses are rounded to the nearest 0.1 mm. Metric plain-end weights are calculated from the metric outside diameters and wall thicknesses using the formula in par 7.1 and rounded to the nearest 0.01 kg/m. Metric hydrostatic pressures are calculated from metric outside diameters and wall thicknesses and metric fiber stresses shown in Sec. 6.
http://compass.astm.org/DIGITAL_LIBRARY/3PC.PREVIEW/eab-65ac-4c37-ac1f-e7d0d5f5b029.htm 01-Jan-93 API SPEC 5LD 2ND ED () Specifcation for CRA or Lined Steel pipes; Second Edition; Effective date: December 31, 1.1 COVERAGEThis specification covers seamless, centrifugal cast, and welded clad steel line pipe and lined steel pipe with improved corrosion resistant properties. The clad and lined steel line pipe specified herein shall be composed of a base metal outside and a corrosion-resistant alloy (CRA) layer inside the pipe. The base material shall conform to API Spec 5L except as modified herein.
The primary product has square ends, but other special end preparation may be furnished by agreement between the purchaser and manufacturer. Included are NPS: 1 in. through 42 in.
Grades of base metal covered by this specification are X42, X46, X52, X56, X60, X65, X70 and X80 and grades intermediate to these. Grades of the CRA layer are LC , , , , and and other grades which are subject to agreement between the purchaser and the manufacturer.
1.2 GENERAL
a. This specification is under the jurisdiction of the Committee on Standardization of Tubular Goods.
b. The purpose of this specification is to provide standards for pipe with improved corrosion resistance suitable for use in conveying gas, water, and oil in both the oil and natural gas industries.
c. Although the plain-end line pipe meeting this specification is primarily intended for field makeup by circumferential welding, the manufacturer will not assume responsibility for field welding.
d. The size designations are nominal pipe sizes. In the text paragraphs herein, where pipe size limits (or size ranges) are given, these are outside-diameter sizes except where stated to be nominal. These outside-diameter size limits and ranges apply also to the corresponding nominal sizes.
1.3 METRIC UNITS
Metric units in this specification are shown in parentheses in the text and in many tables. Outside diameters and wall thicknesses are converted from inch dimensions. The converted diameters are rounded to the nearest 0.1 mm for diameters less than 18 in., and to the nearest 1.0 mm for diameters 18 in. and larger. Wall thicknesses are rounded to the nearest 0.1 mm.
Metric plain-end weights are calculated from the metric outside diameters and wall thicknesses using the formula in 9.1 and rounded to the nearest 0.01 kg/m. Metric hydrostatic pressures are calculated from metric outside diameters and wall thicknesses and metric fiber stresses shown in Sec. 8.
This specification covers seamless and welded clad steel line pipe and lined steel line pipe with enhanced corrosion resistant properties suitable for use in pipeline transportation systems in the petroleum and natural gas industries. The clad and lined steel line pipe specified herein is composed of a carbon steel backing or base material outside (in some cases inside and/or outside) and a corrosion-resistant alloy (CRA) layer or lining inside of the pipe. The base material conforms to API 5L, PSL 2 and applicable annex(es), except as modified herein.
The delivered product usually has square ends, but other special ends may be furnished by agreement between the purchaser and manufacturer. Included are NPS 25 mm (1 in.) through mm (84 in.). Sizes greater than mm (84 in.) are outside of the range of API 5L but may be supplied up to mm (100 in.) by agreement, including requirements for materials.
Grades of base material covered by this specification include X42, X46, X52, X56, X60, X65, X70 and X80 and grades intermediate to these. Grades of the CRA layer are LC , , , , , UNS S, UNS N, Alloy 59 (UNS N), Alloy 254 SMO&#; 1 (UNS S), AL6NX (UNS N) and 1. (UNS N). Other grades are subject to agreement between the purchaser and the manufacturer.
1.2 General
This specification is under the jurisdiction of the API Committee on Standardization of Tubular Goods.
The purpose of this specification is to provide standards for pipe with enhanced corrosion resistance suitable for use in conveying gas, water, and oil in both the oil and natural gas industries.
Although the plain-end line pipe meeting this specification is primarily intended for field make-up by circumferential welding, the manufacturer will not assume responsibility for field welding.
The size designations are nominal pipe sizes. In the text, where pipe size limits (or size ranges) are given, these are outside-diameter sizes except where stated to be nominal. These outside-diameter size limits and ranges apply also to the corresponding nominal sizes.
This specification covers seamless and welded clad steel line pipe and lined steel line pipe with enhanced corrosion-resistant properties suitable for use in pipeline transportation systems in the petroleum and natural gas industries. The clad and lined steel line pipe specified herein is composed of a carbon steel backing or base material outside (in some cases inside and/or outside) and a corrosion-resistant alloy (CRA) layer or lining inside of the pipe. The base material conforms to API 5L (45th Ed.), product specification level (PSL) 2 and applicable annex (es), except as modified herein.
Grades of base material covered by this specification include X42, X46, X52, X56, X60, X65, X70, X80, and grades intermediate to these. Grades of the CRA layer are LC , , , , , unified numbering system (UNS) S, UNS N, UNS N, Alloy 31&#;1 (UNS N), Alloy 59 (UNS N), Alloy 254 SMO&#; 11 (UNS S), Alloy 400 (UNS N), AL6NX (UNS N), and EN1. (UNS N). Other grades are subject to agreement between the purchaser and the manufacturer.
The delivered product usually has square ends, but other special ends may be furnished by agreement between the purchaser and manufacturer. Included are nominal pipe sizes (NPS) 25 mm (1 in.) through mm (84 in.). Sizes greater than mm (84 in.) are outside of the range of API 5L (45th Ed.) but may be supplied up to mm (100 in.) by agreement, including requirements for materials. 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/fde21d56-fb7f-497a-abda-de1b983d8cbd.htm 01-May-15 API SPEC 5LD 4TH ED (E1) CRA Clad or Lined Steel Pipe; Fourth Edition; Effective Date: September 3, 1.1 CoverageThis specification covers seamless and welded clad steel line pipe and lined steel line pipe with enhanced corrosion-resistant properties suitable for use in pipeline transportation systems in the petroleum and natural gas industries. The clad and lined steel line pipe specified herein is composed of a carbon steel backing or base material outside (in some cases inside and/or outside) and a corrosion-resistant alloy (CRA) layer or lining inside of the pipe. The base material conforms to API 5L (45th Ed.), product specification level (PSL) 2 and applicable annex(es), except as modified herein. Grades of base material covered by this specification include X42, X46, X52, X56, X60, X65, X70, X80, and grades intermediate to these. Grades of the CRA layer are LC , , , , , unified numbering system (UNS) S, UNS N, UNS N, Alloy 31&#;1 (UNS N), Alloy 59 (UNS N), Alloy 254 SMO&#; 11 (UNS S), Alloy 400 (UNS N), AL6NX (UNS N), and EN 1. (UNS N). Other grades are subject to agreement between the purchaser and the manufacturer. The delivered product usually has square ends, but other special ends may be furnished by agreement between the purchaser and manufacturer. Included are nominal pipe sizes (NPS) 25 mm (1 in.) through mm (84 in.). Sizes greater than mm (84 in.) are outside of the range of API 5L (45th Ed.) but may be supplied up to mm (100 in.) by agreement, including requirements for materials. 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.
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.
This International Standard does not apply to field use, field testing or field repair of wellhead and christmas tree equipment.
This specification does not apply to field use or field testing. This specification also does not apply to repair of wellhead and tree equipment except for weld repair in conjunction with manufacturing. Tools used for installation and service (e.g. running tools, test tools, wash tools, wear bushings, and lubricators) are outside the scope of this standard.
This specification is applicable to the equipment identified in 4.1 and Section 14.
This specification establishes requirements for four product specification levels (PSLs): PSL 1, PSL 2, PSL 3, and PSL 4. A supplemental designation of PSL 3G applies to PSL 3 products that have satisfied the additional requirements of gas testing. The PSL designations define different levels of technical quality requirements.
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.
Subject matter of Annexes B, C, D, E, F, G, H, I, J, K, L, and M has been arranged in a way that minimizes the impact of changes on users of this document.
This specification identifies requirements and gives recommendations for the performance, dimensional and functional interchangeability, design, materials, testing, inspection, welding, marking, handling, storing, shipment, and purchasing of wellhead and tree equipment for use in the petroleum and natural gas industries.
This specification does not apply to field use or field testing. This specification also does not apply to repair of wellhead and tree equipment except for weld repair in conjunction with manufacturing. Tools used for installation and service (e.g. running tools, test tools, wash tools, wear bushings, and lubricators) are outside the scope of this standard.
This specification is applicable to the equipment identified in 4.1 and Section 14.
This specification establishes requirements for four product specification levels (PSLs): PSL 1, PSL 2, PSL 3, and PSL 4. A supplemental designation of PSL 3G applies to PSL 3 products that have satisfied the additional requirements of gas testing. The PSL designations define different levels of technical quality requirements.
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.
Subject matter of Annexes B, C, D, E, F, G, H, I, J, K, L, and M has been arranged in a way that minimizes the impact of changes on users of this document.
NOTE
Previous editions of this document included reference to and requirements for verification to PR1, standard service (Class I).
2. The types of flanges covered include threaded flanges (line pipe, casing and tubing), slip.-on welding flanges (line pipe and casing), welding-neck flanges (line pipe), blind flanges, and also integral flange,s (facing dimensions only) for valves and fittings.
3. This standard also covers ring-joint gaskets and flange olting, but neither is to be furnished unless the purchase order so states.
4. Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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.
2. The types of flanges covered include threaded flanges (line pipe, casing, and tubing), welding-neck flanges (line pipe), and blind flanges. It covers also dimensional requirements for integral flanges for valves, fittings, and wellheads (see Std 6C and 6E).
3. This standard also covers ring-joint gaskets and flange bolting, but neither shall be furnished unless the purchase order so states.
4. Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for manufacture, sale, or use in connection with any method, apparatus, or product covered b&#; letters patent, nor as insuring anyone against liability for infringement of letters patent.
NOTE: Slip-on flanges are not included in this specification because of very limited use in drilling and production service. Purchasers may obtain slip-on flanges by reference to ASA B16.5.
2. Flange types covered include threaded flanges (line pipe, casing, and tubing), welding-neck flanges (line pipe), and blind flanges. Also covered are integral flange dimensional requirements for valves, fittings, and wellheads (see. Std 6C, 6CM, and GE).
NOTE: Slip-m flanges are not included in this specification because of limited use in drilling and production service. Purchasers may obtain slip-on flanges by reference to ASA B16.5: Steel Pipe Flanges and Flanged Fittings.
3. This standard also covers ring-joint gaskets and flange bolting, but neither shall be furnished unless the purchase order so states.
4. Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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. This specification is for the convenience of purchasers and manufacturers in ordering and producing flanges. It is not intended to inhibit purchasers and producers from purchasing and producing flanges meeting specifications other than those contained herein; nor is it intended in any way to inhibit purchasers from purchasing flanges from companies not authorized to use the API monogram.
This specification is not applicable to subsea pipeline valves, as they are covered by a separate specification, API 6DSS.
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A applies.
Annexes B, C, D, E, F, G, H, I, J, K, L, M, N, and O are annexes that are used in order listed.
1.2 Conformance
1.2.1 Units of Measurement
In this specification, data are expressed in both U.S. customary (USC) and metric (SI) units.
1.2.2 Rounding Except as otherwise required by this specification, to determine conformance with the specified requirements, observed or calculated values shall be rounded to the nearest unit in the last right-hand place of figures used in expressing the limiting value, in accordance with the rounding method of ASTM E29 or ISO -1, Annex B, Rule A.
1.3 Conformance with Specification
A quality management system shall be applied to assist conformance with the requirements of this specification. The manufacturer shall be responsible for conforming with all of the applicable requirements of this specification. It shall be permissible for the purchaser to make any investigation necessary in order to be assured of conformance by the manufacturer and to reject any material that does not conform.
1.4 Processes Requiring Validation
The following operations performed during manufacturing shall be validated, by the manufacturer, in accordance with their quality system as applicable:
&#; nondestructive examination (NDE)&#;reference 8.1;
&#; welding&#;reference Section 7;
&#; heat treating&#;reference 6.1;
&#; external coating/component plating that may impact product performance, by agreement.
This specification defines the requirements for the design, manufacturing, assembly, testing, and documentation of ball, check, gate, and plug valves for application in pipeline and piping systems for the petroleum and natural gas industries.
This specification is not applicable to subsea pipeline valves, as they are covered by a separate specification, API 6DSS.
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A applies.
Annexes B, C, D, E, F, G, H, I, J, K, L, M, N, and O are annexes that are used in order listed.
1.2 Conformance
1.2.1 Units of Measurement
In this specification, data are expressed in both U.S. customary (USC) and metric (SI) units.
1.2.2 Rounding
Except as otherwise required by this specification, to determine conformance with the specified requirements, observed or calculated values shall be rounded to the nearest unit in the last right-hand place of figures used in expressing the limiting value, in accordance with the rounding method of ASTM E29 or ISO -1, Annex B, Rule A.
1.3 Conformance with Specification
A quality management system shall be applied to assist conformance with the requirements of this specification. The manufacturer shall be responsible for conforming with all of the applicable requirements of this specification. It shall be permissible for the purchaser to make any investigation necessary in order to be assured of conformance by the manufacturer and to reject any material that does not conform.
1.4 Processes Requiring Validation
The following operations performed during manufacturing shall be validated, by the manufacturer, in accordance with their quality system as applicable:
&#; nondestructive examination (NDE)&#;reference 8.1;
&#; welding&#;reference Section 7;
&#; heat treating&#;reference 6.1;
&#; external coating/component plating that may impact product performance, by agreement.
This specification is not applicable to sub sea pipeline valves, as they are covered by a separate specification, API 6DSS.
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A applies.
Annexes B, C, D, E, F, G, H, I, J, K, L, M, N, and O are annexes that are used in order listed.
This specification is not applicable to sub sea pipeline valves, as they are covered by a separate specification, API 6DSS.
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A applies.
Annexes B, C, D, E, F, G, H, I, J, K, L, M, N, and O are annexes that are used in order listed.
This specification is not applicable to sub sea pipeline valves, as they are covered by a separate specification, API 6DSS.
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A applies.
Annexes B, C, D, E, F, G, H, I, J, K, L, M, N, and O are annexes that are used in order listed.
This specification is not applicable to sub sea pipeline valves, as they are covered by a separate specification, API 6DSS.
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A applies.
Annexes B, C, D, E, F, G, H, I, J, K, L, M, N, and O are annexes that are used in order listed.
This International Standard is not applicable to valves for pressure ratings exceeding PN 420 (Class ).
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.
This specification is not applicable to valves for pressure ratings exceeding Class .
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.
This document establishes acceptable levels for leakage through the test valve and also external leakage after exposure to a fire for a 30 minute time period.
The burn period has been established on the basis that it represents the maximum time required to extinguish most fires. Fires of greater duration are considered to be of a major magnitude with consequences greater than those anticipated in this test.
This specification was formulated to establish procedures for testing and evaluating the pressure-containing performance of API end connections when exposed to fire. Valves, wellhead seals, or other related equipment, are not included in the scope of this document. The procedures are presented in two parts.
Part I represents conditions in an onshore or open offshore location.
Part II represents conditions in an offshore platform well bay.Background information on fire-resistance of API end connections is contained in API Technical Report 6F1. Further background on fire-resistance improvements of API flanges is contained in API Technical Report 6F2.
1.2 APPLICATIONS
This specification covers API Spec 6A end connections, which include:
a. API Flanged End and Outlet Connections (6B, 6BX, and Segmented).
b. API Threaded End and Outlet Connections.
c. Other End Connections (OECs).
This specification was formulated to establish procedures for testing and evaluating the pressure-containing performance of API end connections when exposed to fire. Valves, wellhead seals, or other related equipment, are not included in the scope of this document. The procedures are presented in two parts.
Part I represents conditions in an onshore or open offshore location.
Part II represents conditions in an offshore platform well bay.
Background information on fire-resistance of API end connections is contained in API Bulletin 6F1. Further background on fire-resistance improvements of API flanges is contained in API Bulletin 6F2.
1.2 APPLICATIONS
This specification covers API Spec 6A end connections, which include:
a. API Hanged End and Outlet Connections (6B, 6BX, and Segmented).
b. API Threaded End and Outlet Connections.
c. Other End Connections (OECs).
This standard establishes acceptable levels for external leakage through an end connector after exposure to a fire for a 30-minute time period. The fire exposure has been established on the basis that it represents the maximum time required to extinguish most fires. Fires of greater duration are of a major magnitude with consequences greater than those anticipated in this test.
This standard covers but is not limited to API 6A and API 6D end connectors.
This standard does not intend to address the qualification of valves, wellhead seals, or other related equipment.
This document establishes acceptable levels of leakage through the test valve and also external leakage after exposure to a fire for a 30-minute time period.
The burn period has been established on the basis that it represents the maximum time required to extinguish most fires. Fires of greater duration are considered to be of a major magnitude with consequences greater than those anticipated in this test.
Other supplementary specifications can be agreed between interested parties for special tolerance requirements, qualification, testing, inspection and finishing.
This part of ISO is applicable to the following preferred rotary shouldered connection designs: a) number (NC) style; b) regular (REG) style; c) full hole (FH) style.
These are traceable to an internationally supported system of gauges and calibration
Other supplementary specifications can be agreed between interested parties for special tolerance requirements, qualification, testing, inspection and finishing.
This part of ISO is applicable to the following preferred rotary shouldered connection designs:
a) number (NC) style;
b) regular (REG) style;
c) full hole (FH) style.
These are traceable to an internationally supported system of gauges and calibration
These connections are intended primarily for use in drill-string components. Other supplementary specifications can be agreed between interested parties for special tolerance requirements, qualification, testing, inspection, and finishing. This standard applies both to newly manufactured connections and connections that are recut after service. It should be realized that recut connections are subject to additional inspection and testing&#;the user is referred to API 7G-2 for such information.
This standard is applicable to the following preferred rotary shouldered connection designs. These are traceable to an internationally supported system of gauges and calibration that can be described as number (NC) style, regular (REG) style, or full-hole (FH) style.
These connections are intended primarily for use in drill-string components. Other supplementary specifications can be agreed between interested parties for special tolerance requirements, qualification, testing, inspection, and finishing. This standard applies both to newly manufactured connections and connections that are recut after service. It should be realized that recut connections are subject to additional inspection and testing&#;the user is referred to API 7G-2 for such information.
This standard is applicable to the following preferred rotary shouldered connection designs. These are traceable to an internationally supported system of gauges and calibration that can be described as number (NC) style, regular (REG) style, or full-hole (FH) style.
1.1 Coverage
This standard specifies the following requirements on rotary shouldered connections for use in petroleum and natural gas industries: dimensional requirements on threads and thread gauges, stipulations on gauging practice and gauge specifications, as well as instruments and methods for inspection of thread connections. These connections are intended primarily for use in drill-string components.
Other supplementary specifications can be agreed between interested parties for special tolerance requirements, qualification, testing, inspection, and finishing. This standard applies both to newly manufactured connections and connections that are recut after service. It should be realized that recut connections are subject to additional inspection and testing&#;the user is referred to API 7G-2 for such information.
This standard is applicable to preferred rotary shouldered connection designs. These are traceable to an internationally supported system of gauges and calibration that can be described as number (NC) style, regular (REG) style, or full-hole (FH) style.
1.2 Application of the API Monogram
If the product (gauge) 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.
Shouldered Connections; Second Edition; Effective Date: June 6,
1.1 CoverageThis standard specifies the following requirements on rotary shouldered connections for use in petroleum and natural gas industries: dimensional requirements on threads and thread gauges, stipulations on gauging practice and gauge specifications, as well as instruments and methods for inspection of thread connections. These connections are intended primarily for use in drill-string components.
Other supplementary specifications can be agreed between interested parties for special tolerance requirements, qualification, testing, inspection, and finishing. This standard applies both to newly manufactured connections and connections that are recut after service. It should be realized that recut connections are subject to additional inspection and testing&#;the user is referred to API 7G-2 for such information.
This standard is applicable to preferred rotary shouldered connection designs. These are traceable to an internationally supported system of gauges and calibration that can be described as number (NC) style, regular (REG) style, or full-hole (FH) style.
For informational purposes, Annex A provides recommendations for installation, lubrication, and maintenance of oil field chain drives and Annex B includes a basic description of roller chain sprockets.
This specification is applicable to the following equipment:
a)rotary tables;
a)rotary bushings;
b)high-pressure mud and cement hoses;
c)piston mud-pump components;
d)drawworks components;
e)manual tongs;
f)safety clamps not used as hoisting devices;
g)blowout preventer (BOP) handling systems;
h)pressure-relieving devices for high-pressure drilling fluid circulating systems;
i)snub lines for manual and power tongs;
j)rotary slips, both manual and powered;
k)slip bowls; and
l)spiders, both manual and powered.
This specification is applicable to the following equipment:
a) rotary tables;
b) rotary bushings;
c) high-pressure mud and cement hoses;
d) piston mud-pump components;
e) draw works components;
f) manual tongs;
g) safety clamps not used as hoisting devices;
h) blowout prevented (BOP) handling systems;
i) pressure-relieving devices for high-pressure drilling fluid circulating systems;
j) snub lines for manual and power tongs;
k) rotary slips, both manual and powered;
l) slip bowls; and
m) spiders, both manual and powered
This specification is applicable to the following equipment:
a) rotary tables;
b) rotary bushings;
c) high-pressure mud and cement hoses;
d) piston mud-pump components;
e) draw works components;
f) manual tongs;
g) safety clamps not used as hoisting devices;
h) blowout prevented (BOP) handling systems;
i) pressure-relieving devices for high-pressure drilling fluid circulating systems;
j) snub lines for manual and power tongs;
k) rotary slips, both manual and powered;
l) slip bowls; and
m) spiders, both manual and powered
This standard was formulated to provide the minimum acceptable requirements for Drill String Non-return Valve (NRV) equip- ment. It covers Drill String Non-return Valves, Non-return Valve Subs, Non-return Valve landing nipples, Non-return Valve Equalizing Heads and all components that establish tolerances and/or clearances which may affect performance or interchange- ability of the NRV equipment. Non-return Valve Subs, Non-return Valve landing nipples, Non-return Valve Equalizing Heads and NRVs manufactured by different facilities or manufacturers may be supplied as separate items.
b) traveling blocks and hook blocks; c) block-to-hook adapters; d) connectors and link adapters; e) drilling hooks; f) tubing hooks and sucker-rod hooks; g) elevator links; h) casing elevators, tubing elevators, drill-pipe elevators and drill-collar elevators; i) sucker-rod elevators; j) rotary swivel-bail adapters; k) rotary swivels; l) power swivels; m) power subs; n) spiders, if capable of being used as elevators; o) wire-line anchors; p) drill-string motion compensators; q) Kelly spinners, if capable of being used as hoisting equipment; r) pressure vessels and piping mounted onto hoisting equipment; s) safety clamps, if capable of being used as hoisting equipment; t) guide dollies for traveling equipment (e.g. hooks, blocks, etc.). This Standard establishes requirements for two product specification levels (PSLs). These two PSL designations define different levels of technical requirements. All the requirements of Section 4 through Section 11 are applicable to PSL 1 unless specifically identified as PSL 2. PSL 2 includes all the requirements of PSL 1 plus the additional practices as stated herein. Supplementary requirements apply only when specified. Annex A gives a number of standardized supplementary requirements.
http://compass.astm.org/DIGITAL_LIBRARY/3PC/4f1e4dc1-8c52--bccd-afa250b9ce06.htm 01-May-14 API SPEC 9A 26TH ED (E1) Specification for Wire Rope; Twenty-Sixth Edition; Effective Date: November 1, This standard specifies the minimum requirements and terms of acceptance for the manufacture and testing of steel wire ropes not exceeding rope grade for the petroleum and natural gas industries. The following products are covered by this specification :&#; wire rope,
&#; bright- or drawn-galvanized wire rope,
&#; well-measuring wire, and
&#; well-measuring strand.
Typical applications include tubing lines, rod hanger lines, sand lines, cable-tool drilling and clean out lines, cable tool casing lines, rotary drilling lines, winch lines, horse head pumping unit lines, torpedo lines, mast-raising lines, guideline tensioner lines, riser tensioner lines, and mooring and anchor lines. Ropes for lifting slings and cranes, and wire for well-measuring and strand for well-servicing, are also included.
The minimum breaking forces for the more common sizes, grades, and constructions of stranded rope are given in tables. However, this standard does not restrict itself to the classes covered by those tables. Other types, such as ropes with compacted strands and compacted (swaged) ropes, may also conform with its requirements. The minimum breaking force values for these ropes are provided by the manufacturer.
For information only, other tables present the minimum breaking forces for large diameter stranded and spiral ropes (i.e. spiral strand and locked coil), while approximate nominal length masses for the more common stranded rope constructions and large diameter stranded and spiral ropes are also given.
&#; wire rope,
&#; bright- or drawn-galvanized wire rope,
&#; well-measuring wire, and
&#; well-measuring strand.
Typical applications include tubing lines, rod hanger lines, sand lines, cable-tool drilling and clean out lines, cable tool casing lines, rotary drilling lines, winch lines, horse head pumping unit lines, torpedo lines, mast-raising lines, guideline tensioner lines, riser tensioner lines, and mooring and anchor lines. Ropes for lifting slings and cranes, and wire for well-measuring and strand for well-servicing, are also included.
The minimum breaking forces for the more common sizes, grades, and constructions of stranded rope are given in tables. However, this standard does not restrict itself to the classes covered by those tables. Other types, such as ropes with compacted strands and compacted (swaged) ropes, may also conform with its requirements. The minimum breaking force values for these ropes are provided by the manufacturer.
For information only, other tables present the minimum breaking forces for large diameter stranded and spiral ropes (i.e. spiral strand and locked coil), while approximate nominal length masses for the more common stranded rope constructions and large diameter stranded and spiral ropes are also given.
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.
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.
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.
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.
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.
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.
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.
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.
This specification specifies the requirements of a quality management system for an organization to demonstrate its ability to consistently provide reliable products and manufacturing-related processes that meet customer and legal requirements.
If an organization performs activities addressed by this specification, no claims to exclusion of those activities are permitted. Where any requirement of this specification cannot be applied due to the nature of an organization, the requirement can be considered for exclusion. Where exclusions are made, the basis for claiming exclusions is to be identified. Furthermore, such exclusions cannot affect the organization's ability, or responsibility, to provide products and related servicing that meet customer and applicable regulatory requirements. Exclusions are limited to the following sections:
&#; 5.4, Design and Development;
&#; 5.7.1.2, Servicing;
&#; 5.7.1.5, Validation of Processes for Production and Servicing;
&#; 5.7.5, Customer-supplied Property;
&#; 5.8, Control of Testing, Measuring, and Monitoring Equipment.
The quality management system requirements specified in this specification are in alignment with the section requirements and format of document used for the provision of services and use of service-related product (API Q2). Information marked &#;NOTE&#; are not requirements but are provided for guidance in understanding or clarifying the associated requirement.
This specification specifies the requirements of a quality management system for an organization to demonstrate its ability to consistently provide reliable products and manufacturing-related processes that meet customer and legal requirements.
This specification specifies the requirements of a quality management system for an organization to demonstrate its ability to consistently provide reliable products and manufacturing-related processes that meet customer and legal requirements.
This specification specifies the requirements of a quality management system for an organization to demonstrate its ability to consistently provide reliable products and manufacturing-related processes that meet customer and legal requirements.
If an organization performs activities addressed by this specification, no claims to exclusion of those activities are permitted. Where any requirement of this specification cannot be applied due to the nature of an organization, the requirement can be considered for exclusion. Where exclusions are made, the basis for claiming exclusions is to be identified. Furthermore, such exclusions cannot affect the organization's ability, or responsibility, to provide products and related servicing that meet customer and applicable regulatory requirements. Exclusions are limited to the following sections:
The quality management system requirements specified in this specification are in alignment with the section requirements and format of document used for the provision of services and use of service- related product (API Q2). Information marked &#;NOTE&#; are not requirements but are provided for guidance in understanding or clarifying the associated requirement.
This document defines the quality management system requirements for service supply organizations for the petroleum, and natural gas industries. It is intended to apply to the execution of upstream services during exploration, development and production in the oil and gas industry. This includes activities involved in oil and gas well construction, intervention, production, and abandonment. This document applies to activities associated with well servicing, equipment repair/maintenance, and inspection activities.
This document specifies requirements of a quality management system for an organization to demonstrate its ability to consistently provide services that meet customer, legal, and other applicable requirements.
This document was developed by a group of upstream technical experts. While this document and/or portions thereof could be applicable to other industry segments, it is recommended that other segments carefully review these requirements to determine their applicability and if necessary develop a segment annex identifying any segment- specific requirements.
Equipment not covered by this part of ISO , unless integral by design, includes bottom drive systems, sucker rods, polished rod clamps, stuffing boxes, electrical controls, instrumentation, external power transmission devices, auxiliary equipment, such as belts, sheaves and equipment guards. These items might or might not be covered by other International Standards.
6A requirements and produced prior to the existence of API 16A.
This standard also covers the testing, inspection, welding, marking, certification, handling, storing, and shipping of equipment repaired or remanufactured per this standard. Repair and remanufacture under this standard includes all remanufacture and all repairs.
This standard is applicable to and establishes requirements for the repair and remanufacture of the following specific equipment:
1) ram blowout preventers (BOPs);
2) ram blocks, operators, packers, and top seals;
3) annular BOPs;
4) annular packing units;
5) hydraulic connectors;
6) drilling spools;
7) adapters;
8) loose connections;
9) clamps;
10) API 6A flanges;
11) other end connections (OECs).
Dimensional interchangeability is limited to end and outlet connections. Simplified examples of surface and subsea equipment defined by this standard are shown in Figures 1 and 2. Maintenance activities are not governed by this document, but the documentation of those activities is included in the scope.
This standard defines various repair/remanufacture specification levels (RSLs) for the equipment identified below as well as the mandatory equipment traceability that is required to prove conformance. Requirements for failure reporting are outlined in Annex D.
6A requirements and produced prior to the existence of API 16A.
This standard also covers the testing, inspection, welding, marking, certification, handling, storing, and shipping of equipment repaired or remanufactured per this standard. Repair and remanufacture under this standard includes all remanufacture and all repairs.
This standard is applicable to and establishes requirements for the repair and remanufacture of the following specific equipment:
1) ram blowout preventers (BOPs);
2) ram blocks, operators, packers, and top seals;
3) annular BOPs;
4) annular packing units;
5) hydraulic connectors;
6) drilling spools;
7) adapters;
8) loose connections;
9) clamps;
10) API 6A flanges;
11) other end connections (OECs).
Dimensional interchangeability is limited to end and outlet connections. Simplified examples of surface and subsea equipment defined by this standard are shown in Figures 1 and 2. Maintenance activities are not governed by this document, but the documentation of those activities is included in the scope.
This standard defines various repair/remanufacture specification levels (RSLs) for the equipment identified below as well as the mandatory equipment traceability that is required to prove conformance. Requirements for failure reporting are outlined in Annex D.
This standard 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 standard can be used for equipment on multiple-well applications.
Rework and repair of used equipment are beyond the scope of this part of this standard.
This standard covers surface control system equipment, subsea-installed control system equipment, and control fluids. This equipment is used for control of subsea production of oil and gas and for subsea water and gas injection services. Where applicable, this standard can be used for subsea processing equipment.
This standard covers surface control system equipment, subsea-installed control system equipment, and control fluids. This equipment is used for control of subsea production of oil and gas and for subsea water and gas injection services. Where applicable, this standard can be used for subsea processing equipment.
API 17G defines a minimum set of requirements for performance, design, materials, testing and inspection, hot forming, welding, marking, handling, storing, and shipping of new build subsea well intervention equipment [through-BOP intervention riser system (TBIRS) and open-water intervention riser system (OWIRS)] as defined herein.
The requirements in this standard apply to equipment whose rated working pressure (RWP) is less than or equal to 103.4 MPa (15,000 psi) or whose rated temperature is less than or equal to 177 °C (350 °F). Equipment ratings that exceed these limits are covered by this document and API 17TR8. For equipment whose ratings exceed the RWP of 103.4 MPa (15,000 psi) or the rated temperature of 177 °C (350 °F), API 17TR8 will take precedence in the event of conflicting requirements with this document.
Structural design methods and criteria given in API 17G are limited to components manufactured from materials that ensure ductile failure modes (e.g. carbon steels, low-alloy steels, and corrosion-resistant alloys). Components manufactured from materials that may not ensure ductile failure modes (e.g. composite materials, titanium, and titanium alloys) are beyond the scope of this standard.
Within this document, the following apply:
The standard covers equipment that is connected to a fluid conduit tieback riser, either inside the marine riser (TBIRS) or open water (OWIRS). Intervention equipment such as riserless light well intervention systems, downline connected equipment, and remotely operated vehicle (ROV) intervention equipment are outside the scope of this standard.
The objective of this document is to provide specifications and a consistent methodology for testing performed on hydraulic fracturing and/or gravel-packing proppants. Methodologies and specifications (where applicable) are provided for:
&#; sieve analysis and median diameter determination;
&#; sphericity and roundness;
&#; acid solubility;
&#; turbidity;
&#; loose pack bulk density, apparent density, and absolute density;
&#; crush resistance;
&#; loss on ignition.
Proppant size designation is as per industry standard. It is based on the maximum and minimum size determination by sieve analysis and ASTM 1 sieve number (and not as per standard opening expressed in micrometers).
Proppants in this document are sand, ceramic media, resin-coated proppants, gravel-packing media, and other similarly used materials for hydraulic fracturing and gravel-packing operations.
This API standard specifies requirements for the 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 different FSLs. These FSL designations define different levels of forged product technical, quality, and qualification requirements.
This standard specifies requirements for the design, development, and qualification of nondestructive examination (NDE) methods used in the manufacturer of equipment for the petroleum and natural gas industries.
1.2 Applicability
This is applicable to suppliers providing NDE services for equipment used in the oil and natural gas industries. The requirements of this standard apply to magnetic particle, liquid penetrant, radiography, and ultrasonic methods of NDE.
This standard specifies requirements for the design, development, and qualification of nondestructive examination (NDE) methods used in the manufacturer of equipment for the petroleum and natural gas industries.
1.2 Applicability
This is applicable to suppliers providing NDE services for equipment used in the oil and natural gas industries. The requirements of this standard apply to magnetic particle, liquid penetrant, radiography, and ultrasonic methods of NDE.
This is applicable to suppliers providing NDE services for equipment used in the oil and natural gas industries. The requirements of this standard apply to magnetic particle, liquid penetrant, radiography, and ultrasonic methods of NDE.
1.2 Applicability
The requirements of this standard apply to welding operations performed in a welding facility or in the field. Included are pressure-containing, pressure-controlling, overlay, and structural welds.
NOTE This standard does not limit the responsibility of any manufacturer of commercial products using welding services and manufactured to an API standard from its responsibility for compliance with all applicable requirements of that API standard.
This standard specifies requirements for the qualification of suppliers of heat treatment services used in the manufacture of equipment for the petroleum and natural gas industries.
1.2 Applicability
This standard is applicable to suppliers providing heat treatment services where API product standards require such services or otherwise specified as a requirement for conformance. The requirements of this standard apply to batch heat treatment operations that establish or affect the final mechanical properties and include stress relief operations. This standard applies to carbon steel, low-alloy steel, stainless steel, and nickel-base alloys. Case hardening, induction hardening, and flame hardening are not covered by this standard.
1.3 Heat Treatment Specification Levels (HSLs)
This standard establishes the requirements for three heat treatment specification levels (HSLs). These HSL designations define different levels of heat treatment technical, quality, and qualification requirements.
This API standard specifies requirements for the qualification of distributors of metallic materials used in the petroleum and natural gas industries.
1.2 Applicability
This standard is applicable to distributors of metallic bar, plate, and tubular products where API product standards require such services or are otherwise specified as a requirement for compliance. For organizations that manufacture and distribute metallic material, this standard only addresses the distribution portion of their processes.
NOTE This standard does not limit the responsibility of any manufacturer of commercial products utilizing metallic materials and manufactured to an API Standard from its responsibility for compliance with all applicable requirements of that API Standard.
1.3 Distributor Qualification Level (DQL)
This API standard establishes the requirements for two distributor qualification levels (DQL). These DQL levels define different levels of distributor quality controls and qualification requirements.
1.2 Applicability This standard is applicable to distributors of metallic bar, plate, and tubular products where API product standards require such services or are otherwise specified as a requirement for compliance. For organizations that manufacture and distribute metallic material, this standard only addresses the distribution portion of their processes.
NOTE This standard does not limit the responsibility of any manufacturer of commercial products utilizing metallic materials and manufactured to an API Standard from its responsibility for compliance with all applicable requirements of that API Standard.
1.3 Distributor Qualification Level (DQL) This API standard establishes the requirements for two distributor qualification levels (DQL). These DQL levels define different levels of distributor quality controls and qualification requirements.
and Natural Gas Industries; First Edition
1.1 PurposeThis API standard specifies requirements for the qualification of manufacturers of polymeric seals used in the petroleum and natural gas industries.
1.2 Applicability
This standard is applicable to the manufacturers of polymeric seals where API product standards require such services or are otherwise specified as a requirement for compliance. Compliance with this standard is not required to demonstrate compliance with any other API standard or specification. This standard does not consider entities that solely perform assembly of outside manufactured parts as a polymeric seal manufacturer.
NOTE This standard does not limit the responsibility of any manufacturer of commercial products utilizing polymeric seals and manufactured to an API standard from its responsibility for compliance with all applicable requirements of that API standard.
This standard is applicable to suppliers providing heat treatment services where API product standards specify this standard as a requirement for conformance. The requirements of this standard apply to continuous and semi-continuous heat treatment operations that can establish or affect the final mechanical properties. For batch type heat treatment refer to API 20H. This standard is applicable to products in tubular, bar, plate, forgings, castings and upset forged forms. Heat treat that imparts surface hardening or case hardening is outside the scope of this document.
&#; the oxygen level in the vapor space is too low to support combustion, and
&#; any gases in or flowing out of the confined space are below flammable or reactive levels.
Typical inert entry work in the petroleum and petrochemical industry includes work to service or replace catalyst in reactors.
The provisions of this standard do not apply to the riser systems of mobile offshore drilling units (MODUs).
There is significant interaction among the subsystems in a floating production system. Hull motions affect risers and mooring, and conversely, risers and mooring affect hull motions. Global behavior of the system provides input to assessment of subsystems. Assessment of a subsystem provides feedback (loads) for assessment of the hull and other subsystems.
Determination of the boundaries of a riser system and management of the interactions with other subsystems is the responsibility of the operator.
A riser system is an assembly of components, including pipe and connectors. A riser system can include a riser tensioning system, buoyancy modules, etc. Pipe components can be steel, titanium, or unbonded flexible pipe. Design considerations for unbonded flexible pipe are included primarily by reference to API 17B and API 17J. Design considerations for titanium alloy pipe are included primarily by reference to DNV-RP F201. Steel and titanium pipe are referred to as rigid pipe and unbonded flexible pipe is referred to as flexible pipe.
All or part of several existing codes, standards, specifications, and recommended practices are included by reference.
Design loads and conditions are described in Section 4. Structural design criteria for rigid pipe are in Section 5. Structural capacity formulae for steel pipe are also in Section 5. Additional requirements for components, including pipe, are in Section 6. Material requirements are in Section 7. Fabrication and installation requirements are in Section 8. Integrity Management is addressed in Section 9.
1.1.1 The purpose of this standard is to provide requirements on the installation and testing of blowout prevention equipment systems on land and marine drilling rigs (barge, platform, bottom-supported, and floating).
1.1.2 Blowout preventer equipment systems are comprised of a combination of various components. The following components are required for operation under varying rig and well conditions:
a) blowout preventers (BOPs);
b) choke and kill lines;
c) choke manifolds;
d) control systems;
e) auxiliary equipment.
1.1.3 The primary functions of these systems are to confine well fluids to the wellbore, provide means to add fluid to the wellbore, and allow controlled volumes to be removed from the wellbore.
1.1.4 Diverters, shut-in devices, and rotating head systems (rotating control devices) are not addressed in this standard (see API 64 and API 16RCD, respectively); their primary purpose is to safely divert or direct flow rather than to confine fluids to the wellbore.
1.2 Well Control
Procedures and techniques for well control are not included in this standard since they are beyond the scope of equipment systems contained herein.
1.3 BOP Installations
This standard contains a section pertaining to surface BOP installations followed by a section on subsea BOP 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 can be equally effective in addressing well requirements and achieving safety and operational efficiency.
1.5 Extreme High- and Low-temperature Operations
1.5.1 Although operations are being conducted in areas of extreme high and low temperatures, a section specifically applicable to these service conditions is not included since current practice generally results in protecting the existing BOP equipment from these environments.
1.5.2 High and low temperature values are identified in API 16A for metallic and nonmetallic parts. The use of metallic and nonmetallic components shall be verified for use in temperatures above or below those identified in API 16A.
1.1.1 The purpose of this standard is to provide requirements on the installation and testing of blowout prevention equipment systems on land and marine drilling rigs (barge, platform, bottom-supported, and floating).
1.1.2 Blowout preventer equipment systems are comprised of a combination of various components. The following components are required for operation under varying rig and well conditions:
a) blowout preventers (BOPs);
b) choke and kill lines;
c) choke manifolds;
d) control systems;
e) auxiliary equipment.
1.1.3 The primary functions of these systems are to confine well fluids to the wellbore, provide means to add fluid to the wellbore, and allow controlled volumes to be removed from the wellbore.
1.1.4 Diverters, shut-in devices, and rotating head systems (rotating control devices) are not addressed in this standard (see API 64 and API 16RCD, respectively); their primary purpose is to safely divert or direct flow rather than to confine fluids to the wellbore.
1.2 Well Control
Procedures and techniques for well control are not included in this standard since they are beyond the scope of equipment systems contained herein.
1.3 BOP Installations
This standard contains a section pertaining to surface BOP installations followed by a section on subsea BOP 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 can be equally effective in addressing well requirements and achieving safety and operational efficiency.
1.5 Extreme High- and Low-temperature Operations
1.5.1 Although operations are being conducted in areas of extreme high and low temperatures, a section specifically applicable to these service conditions is not included since current practice generally results in protecting the existing BOP equipment from these environments.
1.5.2 High and low temperature values are identified in API 16A for metallic and nonmetallic parts. The use of metallic and nonmetallic components shall be verified for use in temperatures above or below those identified in API 16A.
Well control equipment systems are designed with components that provide wellbore pressure control in support of well operations. The following components may be used for operation under varying rig and well conditions:
&#; BOPs (blowout preventers);
&#; Choke and kill lines;
&#; Choke manifolds;
&#; Control systems;
&#; Auxiliary equipment.
The primary functions of these systems are to confine well fluids to the wellbore, provide means to add fluid to the wellbore, and allow controlled volumes to be removed from the wellbore.
Diverters, shut-in devices, and rotating head systems (rotating control devices) are not addressed in this standard (see API 64 and API 16RCD, respectively); their primary purpose is to safely divert or direct flow rather than to confine fluids to the wellbore.
Procedures and techniques for well control are not included in this standard because they are beyond the scope of the equipment systems contained herein.
This standard contains a section pertaining to surface BOP installations followed by a section pertaining to subsea BOP installations.
To the extent that this document recommends specific equipment arrangements, it is recognized that other arrangements can be equally effective in addressing well requirements and achieving safety and operational efficiency.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength.
1.1 This specification covers high-test line pipe in grades X42 and higher. Requirements on grades X42, X46, and X52 are fully specified. Requirements on intermediate wall thicknesses and/ or intermediate grades (those between X42 and X46 and between X46 and X52) and on grades higher than X52 are specified except for chemical compositions and certain physical properties which are subject to agreement between the purchaser and manufacturer, within the limitation that the agreed-upon requirements must be consistent with the corresponding requirements specified herein for grades X42, X46, and X52.
1.2 Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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. This specification is for the convenience of purchasers and manufacturers in ordering and producing pipe and is not intended to inhibit purchasers and producers from purchasing and producing pipe meeting specifications other than those contained herein nor is it intended in any way to inhibit purchasers from purchasing pipe from companies not authorized to use the API monogram.
1. This specification covers various grades of high-test line pipe. The proper grade designations to be used under this specification comprise the letter X followed by the first two digits of the specified minimum yield strength. Thus X42 designates the grade having a specified minimum yield strength of 42,000 psi; X52, 52,000 psi, etc. Complete requirements are specified for the X42 grade only, these including processes of manufacture, chemical and physical requirements, methods of test, dimensions on diameter, thickness, length, etc. Higher strength grades available under this specification are subject to agreement between the purchaser and the manufacturer as to chemical, tensile and flattening test requirements, but in other respects are subject to the requirements as given herein.
2. Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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.
Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for manufacture, slae, or use in connection with any mehtod, apparatus, or product covered by letters patent, nor as insuringanyone against liability for infringement of letters patent. This specification is for the convenience of purchasers and manufacturers in ordering and producing pipe and is not intended to inhibit purchasers from purchasing and producing pipe meeting specifications other than those contained herein nor is it intended in any way to inhibit purchasers from purchasing pipe from companies not authorized to use the API monogram.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength.
1.1 This specification covers high-test line pipe in grades X42 and higher. Requirements on grades X42, X46, and X52, are fully specified. Requirements on grade X60 seamless, electric flash welded, and automatic submerged-arc welded high-test line pipe are fully specified except that other chemical compositions are permitted subject to agreement between the purchaser and manufacturer. Requirements on grade X60 electric-resistance welded high-test line pipe are subject to agreement between the purchaser and manufacturer. Requirements on intermediate wall thicknesses and/or intermediate grades (those between grades X42, X46, X52 and X60) and on grades higher than X60 are specified except for chemical compositions and certain physical properties which are subject to agreement between the purchaser and manufacturer, within the limitation that the agreed upon requirements must be consistent with the corresponding requirements specified herein for grades X42, X46, X52, and X60.
1.2 Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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. This specification is for the convenience of purchasers and manufacturers in ordering and producing pipe and is not intended to inhibit purchasers and producers from purchasing and producing pipe meeting specifications other than those contained herein nor is it intended in any way to inhibit purchasers from purchasing pipe from companies not authorized to use the API monogram.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength.
1.1 This specification covers high-test line pipe in grades X42 and higher. Requirements on grades X42, X46, and X52, are fully specified. Requirements on grade X60 seamless, electric flash welded, and automatic submerged-arc welded high-test line pipe are fully specified except that other chemical compositions are permitted subject to agreement between the purchaser and manufacturer. Requirements on grade X60 electric-resistance welded high-test line pipe are subject to agreement between the purchaser and manufacturer. Requirements on intermediate wall thicknesses and/or intermediate grades (those between grades X42, X46, X52 and X60) and on grades higher than X60 are specified except for chemical compositions and certain physical properties which are subject to agreement between the purchaser and manufacturer, within the limitation that the agreed upon requirements must be consistent with the corresponding requirements specified herein for grades X42, X46, X52, and X60.
1.2 Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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. This specification is for the convenience of purchasers and manufacturers in ordering and producing pipe and is not intended to inhibit purchasers and producers from purchasing and producing pipe meeting specifications other than those contained herein nor is it intended in any way to inhibit purchasers from purchasing pipe from companies not authorized to use the API monogram.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength.
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, and grades intermediate thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, and X65.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.*
1.3 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.
1.4 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 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.
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.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength.
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, and grades intermediate thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, and X65.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.*
1.3 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.
1.4 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 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.
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.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength.
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, and grades intermediate thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, and X65. Grade X60 or higher pipe shall not be substituted for pipe ordered for grade X52 and lower without purchaser approval.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.*
1.3 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.
1.4 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 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.
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.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength.
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, and grades intermediate thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, and X65. Grade X60 or higher pipe shall not be substituted for pipe ordered for grade X52 and lower without purchaser approval.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.
1.3 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.
1.4 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 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.
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.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength,
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, X70," and grades intermediate" thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, X65 and X70. Grade X60 or higher pipe shall not be substituted for pipe ordered for grade X52 and lower without purchaser approval.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.**
1.3 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.
I..t 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 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.
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,
Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength,
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, X70," and grades intermediate" thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, X65 and X70. Grade X60 or higher pipe shall not be substituted for pipe ordered for grade X52 and lower without purchaser approval.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.**
1.3 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.
I..t 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 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.
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,
NOTE: The grade designations used herein comprise the letter X fallowed by the first two digits of the specified minimum yield strength.
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, X70, and grades intermediate thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, X65 and X70. Grade X60 or higher pipe shall not be substituted for pipe ordered for grade X52 and lower without purchaser approval. Requirements for through-the-flowline (TFL) pipe are provided in Appendix E, Supplemental Requirements.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.*
1.3 Nothing contained in any API specification is to he 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.
1.4 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 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.
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.
NOTE: The grade designations used herein comprise the letter X fallowed by the first two digits of the specified minimum yield strength.
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, X70, and grades intermediate thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, X65 and X70. Grade X60 or higher pipe shall not be substituted for pipe ordered for grade X52 and lower without purchaser approval. Requirements for through-the-flowline (TFL) pipe are provided in Appendix E, Supplemental Requirements.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.*
1.3 Nothing contained in any API specification is to he 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.
1.4 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 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.
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.
NOTE: The grade designations used herein comprise the letter X fallowed by the first two digits of the specified minimum yield strength.
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, X70, and grades intermediate thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, X65 and X70. Grade X60 or higher pipe shall not be substituted for pipe ordered for grade X52 and lower without purchaser approval. Requirements for through-the-flowline (TFL) pipe are provided in Appendix E, Supplemental Requirements.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.*
1.3 Nothing contained in any API specification is to he 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.
1.4 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 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.
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.
NOTE: The grade designations used herein comprise the letter X fallowed by the first two digits of the specified minimum yield strength.
1.1 Coverage. This specification covers high-test line pipe in grades X42, X46, X52, X56, X60, X65, X70, and grades intermediate thereto. The chemical composition and certain physical properties of intermediate grades are subject to agreement between the purchaser and manufacturer. The agreed upon requirements must be consistent with the corresponding requirements for grades X42, X46, X52, X56, X60, X65 and X70. Grade X60 or higher pipe shall not be substituted for pipe ordered for grade X52 and lower without purchaser approval. Requirements for through-the-flowline (TFL) pipe are provided in Appendix E, Supplemental Requirements.
1.2 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 to in any way inhibit the purchase of products from companies not authorized to use the API monogram.*
1.3 Nothing contained in any API specification is to he 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.
1.4 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 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.
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. The marking requirements, including the API monogram, are an integral part of API specifications. Products purchased to API specifications must be marked in accordance with the requirements of the marking section of the appropriate specification. However, the American Petroleum Institute does not represent, warrant guarantee that products bearing the API monogram do in fact conform to the applicable API standard or specification.
1. This specification covers various grades of high-test line pipe. The proper grade designations to be used under this specification comprise the letter X followed by the first two digits of the specified minimum yield strength. Thus X42 designates the grade having a specified minimum yield strength of 42,000 psi; X52, 52,000 psi, etc. Complete requirements are specified for the X42 grade only, these including processes of manufacture, chemical and physical requirements, methods of test, dimensions on diameter, thickness, length, etc. Higher strength grades available under this specification are subject to agreement between the purchaser and the manufacturer as to chemical, tensile and flattening test requirements, but in other respects are subject to the requirements as given herein.
2. Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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. This specification covers various grades of high-test line pipe. The proper grade designations to be used under this specification comprise the letter X followed by the first two digits of the specified minimum yield strength. Thus X42 designates the grade having a specified minimum yield strength of 42,000 psi; X52, 52,000 psi, etc. Complete requirements are specified for the X42 grade only, these including processes of manufacture, chemical and physical requirements, methods of test, dimensions on diameter, thickness, length, etc. Higher strength grades available under this specification are subject to agreement between the purchaser and the manufacturer as to chemical, tensile and flattening test requirements, but in other respects are subject to the requirements as given herein.
2. Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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. This specification covers high-test line pipe in grades X42 and higher. The grade designations to be used under this specification comprise the letter X followed by the first two digits of the specified minimum yield strength. Requirements on process of manufacture, physical properties, methods of test, dimensions, and test pressures are specified for grades X42, X46, and X52. Chemical and flattening test requirements are specified for grade X42 only, such requirements for grades X46 and X52 being subject to agreement between the purchaser and the manufacturer. Other grades, available under this specification, are subject to agreement between the purchaser and the manufacturer as to chemical, tensile, and flattening-test requirements, but are subject to all other requirements as given herein.
2. Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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.
Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for manufacture, slae, or use in connection with any mehtod, apparatus, or product covered by letters patent, nor as insuringanyone against liability for infringement of letters patent.
Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for manufacture, slae, or use in connection with any mehtod, apparatus, or product covered by letters patent, nor as insuringanyone against liability for infringement of letters patent.
Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for manufacture, slae, or use in connection with any mehtod, apparatus, or product covered by letters patent, nor as insuringanyone against liability for infringement of letters patent.
NOTE: The grade designations used herein comprise the letter X fallowed by the first two digits of the specified minimum yield strength.
1. This specification covers high-test line pipe in grades X42 and higher. Requirements on grades X42, X46, and X52 are fully specified. Requirements on intermediate grades (those between X42 and X46 and between X46 and X52) and on grades higher than X52 are specified except for chemical compositions and certain physical properties which are subject to agreement between the purchaser and manufacturer, within the limitation that the agreed-upon requirements must be consistent with and proportional to the corresponding requirements specified herein for grades X42, X46, and X52.
2. Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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.
NOTE: The grade designations used herein comprise the letter X followed by the first two digits of the specified minimum yield strength.
1. This specification covers high-test line pipe in grades X42 and higher. Requirements on grades X42, X46, and X52 are fully specified. Requirements on intermediate grades (those between X42 and X46 and between X46 and X52) and on grades higher than X52 are specified except for chemical compositions and certain physical properties which are subject to agreement between the purchaser and manufacturer, within the limitation that the agreed-upon requirements must be consistent with and proportional to the corresponding requirements specified herein for grades X42, X46, and X52.
2. Nothing contained in this specification is to be construed as granting any right, by implication or otherwise, for 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. This specification is for the convenience of purchasers and manufacturers in ordering and producing pipe and is not intended to inhibit purchasers and producers from purchasing and producing pipe meeting specifications other than those contained herein nor is it intended in any way to inhibit purchasers from purchasing pipe from companies not authorized to use the API monogram.
This document provides requirements for age-hardened nickel-base alloys that are intended to supplement the existing requirements of API 6A. For downhole applications refer to API 5CRA.
These additional requirements include detailed process control requirements and detailed testing requirements. The purpose of these additional requirements is to ensure that the age-hardened nickel-base alloys used in the manufacture of API 6A pressure-containing and pressure-controlling components are not embrittled by the presence of an excessive level of deleterious phases and meet the minimum metallurgical quality requirements
.1.2 Applicability
This standard is intended to apply to pressure-containing and pressure-controlling components as defined in API 6A. Requirements of this standard may be applied by voluntary conformance by a manufacturer, normative reference in API 6A or other product specification(s), or by contractual agreement.
This document provides requirements for age-hardened nickel-base alloys that are intended to supplement the existing requirements of API 6A. For downhole applications refer to API 5CRA.
These additional requirements include detailed process control requirements and detailed testing requirements. The purpose of these additional requirements is to ensure that the age-hardened nickel-base alloys used in the manufacture of API 6A pressure-containing and pressure-controlling components are not embrittled by the presence of an excessive level of deleterious phases and meet the minimum metallurgical quality requirements.
Applicability
This standard is intended to apply to pressure-containing and pressure-controlling components as defined in API 6A. Requirements of this standard may be applied by voluntary conformance by a manufacturer, normative reference in API 6A or other product specification(s), or by contractual agreement.
This document provides requirements for age-hardened nickel-base alloys that are intended to supplement the existing requirements of API 6A. For downhole applications refer to API 5CRA.
These additional requirements include detailed process control requirements and detailed testing requirements. The purpose of these additional requirements is to ensure that the age-hardened nickel-base alloys used in the manufacture of API 6A pressure-containing and pressure-controlling components are not embrittled by the presence of an excessive level of deleterious phases and meet the minimum metallurgical quality requirements.
Applicability
This standard is intended to apply to pressure-containing and pressure-controlling components as defined in API 6A. Requirements of this standard may be applied by voluntary conformance by a manufacturer, normative reference in API 6A or other product specification(s), or by contractual agreement.
This document provides requirements for age-hardened nickel-base alloys that are intended to supplement the existing requirements of API 6A. For downhole applications refer to API 5CRA.
These additional requirements include detailed process control requirements and detailed testing requirements. The purpose of these additional requirements is to ensure that the age-hardened nickel-base alloys used in the manufacture of API 6A pressure-containing and pressure-controlling components are not embrittled by the presence of an excessive level of deleterious phases and meet the minimum metallurgical quality requirements.
Applicability
This standard is intended to apply to pressure-containing and pressure-controlling components as defined in API 6A. Requirements of this standard may be applied by voluntary conformance by a manufacturer, normative reference in API 6A or other product specification(s), or by contractual agreement.
This document provides requirements for age-hardened nickel-base alloys that are intended to supplement the existing requirements of API 6A. For downhole applications refer to API 5CRA.
These additional requirements include detailed process control requirements and detailed testing requirements. The purpose of these additional requirements is to ensure that the age-hardened nickel-base alloys used in the manufacture of API 6A pressure-containing and pressure-controlling components are not embrittled by the presence of an excessive level of deleterious phases and meet the minimum metallurgical quality requirements.
Applicability
This standard is intended to apply to pressure-containing and pressure-controlling components as defined in API 6A. Requirements of this standard may be applied by voluntary conformance by a manufacturer, normative reference in API 6A or other product specification(s), or by contractual agreement.
additional requirements and validation of the bonnet assembly inclusive of stem seals.
Validation of the actuator is outside the scope of this standard.
NOTE This standard does not contain the validation requirements for Class I safety valves.
NOTE SSV/USV system architecture and power/control systems for SSVs/USVs are addressed in safety system documents such as API 14C.
This International Standard is applicable to all types of electric, pneumatic and hydraulic actuators, inclusive of mounting kit, installed on pipeline valves.
This International Standard is not applicable to actuators installed on control valves, valves being used for regulation, valves in sub-sea service, handheld powered devices, stand-alone manually operated gearboxes, instrument tubing and associated fittings and actuator control equipment.
components, and is applicable to all types of electric, pneumatic, and hydraulic actuators, inclusive of mounting
kit, installed on valves that conform to API Specification 6D.
This standard is not applicable to actuators installed on control valves, valves being used for regulation, valves
in subsea service, handheld powered devices, manually operated gearboxes, instrument tubing and associated
fittings, and actuator control equipment.
This standard applies to valves with one or more closure members.
This standard establishes acceptable levels for leakage through the test valve and external leakage after exposure to a fire for a 30-minute time period. The fire exposure test period has been established on the basis that it represents the maximum time required to extinguish most fires. Fires of greater duration are considered to be of a major magnitude, with consequences greater than those anticipated in this test.
This standard is not intended to address the qualification of valve actuators (including manually operated gearboxes). This standard does not cover check valves, pressure boundary penetration, external fittings, or end connections.
This standard applies to valves with one or more closure members.
This standard establishes acceptable levels for leakage through the test valve and external leakage after exposure to a fire for a 30-minute time period. The fire exposure test period has been established on the basis that it represents the maximum time required to extinguish most fires. Fires of greater duration are considered to be of a major magnitude, with consequences greater than those anticipated in this test.
This standard is not intended to address the qualification of valve actuators (including manually operated gearboxes). This standard does not cover check valves, pressure boundary penetration, external fittings, or end connections.
This standard applies to valves with one or more closure members.
This standard establishes acceptable levels for leakage through the test valve and external leakage after exposure to a fire for a 30-minute time period. The fire exposure test period has been established on the basis that it represents the maximum time required to extinguish most fires. Fires of greater duration are considered to be of a major magnitude, with consequences greater than those anticipated in this test.
This standard is not intended to address the qualification of valve actuators (including manually operated gearboxes). This standard does not cover check valves, pressure boundary penetration, external fittings, or end connections.
This standard is based on ASME Boiler and Pressure Vessel Code, Section VIII, Division 2, Appendix 4 ( edition with and addenda) but includes further limits established for oil and gas products as determined by API standardization committees. It includes closed-form solutions and methods for elastic analysis, elastic-plastic analysis, and guidance on finite element analysis methods. The methodology assumes ductile metallic material behavior and has no provision for material defects.
Fatigue analysis is outside the scope of this document.
Fatigue analysis is outside the scope of this document. Bolting allowable stresses are given in API product specifications and are outside the scope of this document.
This standard is intended to be used in a laboratory environment and is not intended for use in the field during operations. The testing requirements in this standard are not represented at well conditions. This standard is divided into four major areas: machine apparatus, procedures, materials, and reporting.
This standard will not address the significance of specific data values. It is the responsibility of the user of this standard to establish the appropriate test data values that are acceptable based on their respective application, operational limitations, and safety practices.
The definitions in this report were designed to provide a consistent basis for the reporting and interpretation of petroleum industry statistics. They are not intended to meet definitional requirements for disciplines such as taxation, engineering and law.
To provide a broader understanding of some of the refinery aspects, the "Layman's Guide to a U.S. Refinery" is included. This guide provides a general understanding of some of the terms used in refining operations.
This report was developed in by an ad hoc task group consisting of representatives of federal and state agencies and trade associations, and was reviewed and updated by the API's Committee on Supply and Consumption Statistics in .
This standard covers design, materials, face-to-face dimensions, pressure-temperature ratings, and examination, inspection and test requirements for gray iron, ductile iron, bronze, steel, nickel-based alloy, or special alloy butterfly valves.
1.2
If product is supplied bearing the API Monogram and manufactured at a facility licensed by API, the requirements of Annex A apply.
1.3
The following two categories of butterfly valves are included.
a) Category A&#; Manufacturer's rated cold working pressure (CWP) butterfly valves, usually with a concentric disc and seat configuration. Sizes covered are NPS 2 to NPS 48 for valves having ASME Class 125 or Class 150 flange bolting patterns.
b) Category B&#; ASME Class and pressure-temperature rated butterfly valves that have an offset seat and either an eccentric or a concentric disc configuration. These valves may have a seat rating less than the body rating. Sizes covered are listed below.
&#; For lug and wafer, Class 150: NPS 3 to NPS 48.
&#; For double-flanged long pattern, Class 150, 300, and 600: NPS 3 to NP36.
&#; For double-flanged short pattern, Class 150 and Class 300: NPS 3 to NPS 48.
&#; For double-flanged short pattern, Class 600: NPS 3 to NPS 24.
Information to be specified by the purchaser is shown in Annex
1.4
Valve configurations include double flanged, lug- and wafer-type with facings that permits installation between ASME and MSS flanges that conform to the standards and specifications listed in Section 2. Typical valve construction and nomenclature for valve parts are shown in Annex C.
This report documents:
a. The proposed changes for temperatures.
b. The process used to develop the proposed changes.
c. The process used to develop temperatures in API Specifi-cation(Spec) 10, 5th Edition well-simulation test schedules.
d. The comparison of temperature data sets used to developthe proposed changes to temperatures in API Spec 10, 5thEdition, well-simulation test schedules. Additionally, this report compiles most of the temperaturedata collected by the industry to date into a single documentthat may serve others involved in similar efforts in the future.
The API and ISO standardization committees have produced specifications, testing, and recommended practices for the use of bow-type centralizers, but to date, the petroleum industry does not have standards for the selection and use of solid or rigid centralizers, even though those devices are widely used. Additionally, the industry does not have standardized testing methods to verify functionality and reliability of centralizers. This is a problem for the operator in making an intelligent selection for centralizers to use in the well. Some testing procedures are available, but because they are not standardized, they tend to hinder communication between manufacturers and end users.
1.2 The design calculations are based on correlations of the test data that were obtained during the research phase of the project. Sucker Rod Pumping Research, Inc., before its dissolution, released these correlated test results to the American Petroleum Institute for publication. This technical report for the design calculations of sucker rod pumping systems using conventional pumping units is based on these correlations.
1.3 Three discussions included in the final reports of test results by Midwest Research Institute have been published for permanent reference in API Drilling and Production Practice (). These discussions include the following topics:
a) vibration characteristics of sucker-rod strings;
b) physical characteristics of sucker rods;
c) dimensional analysis of sucker-rod pumping systems.
1.4 A catalog of over dynamometer cards derived from the electronic analog computer for many combinations of the independent non-dimensional parameters Fo/Skr and N/No was included in the material released to API by Sucker Rod Pumping Research, Inc. This catalog has been printed as API 11L2, Catalog of Analog Computer Dynamometer Cards.
1.5 Two computer programs have been developed from the data in API 11L. One program developed tabular material calculated for depths of ft to 12,000 ft in increments of 500 ft and for production rates of 100 barrels/day to over barrels/day in varying increments. Rod and pump size combinations as listed in Table 4.1 were used, except for the elimination of rod no. 88 and rod no. 99. All API stroke lengths are covered. This material is printed as API 11L3, Sucker Rod Pumping System Design Book.
1.2 The International System of Units (SI) is used in this Technical Report. However, testing data acquisition can be conducted using US customary units (USC).
1.3 Factors included in Annex A Table A.1 permit conversions of USC units to SI units or SI units to USC units.
Additional field failures in CaCl2 brines have been linked to ingress of acidic gas containing CO2 and H2S and to exposure to air. SCC of martensitic stainless steel (SS), (13 % Cr, 6 % Ni, 2 % Mo) was attributed to downhole leakage of acidic gas [2], whereas SCC of a duplex SS tubing (25 % Cr, 3 % Mo) was attributed to air in the gas cap above column of brine. [3]
To understand the effects of brine compositions on the CRAs, a joint industry project was formed under the auspices of the American Petroleum Institute (API). It has been known as the CRAs in Brine Testing Program. Under its auspices, work has been underway for a number of years on understanding the interaction of brine chemistry and CRAs.
The current paper evaluates the SCC risks of a range of CRAs in various halide brine compositions for the case of exposure to acidic production gas (CO2+H2S). Also evaluated are SCC risks due to air exposure. However, the testing became focused on a group of martensitic stainless steels alloyed with Ni and Mo, that are collectively referred to as modified 13Cr martensitic SS, or alternatively in some publications as super (S13Cr) martensitic SSs. Most tests evaluated the as-received brine, excluding proprietary additives such as corrosion inhibitor or oxygen scavengers. For completeness and comparison, test results provided by member companies in the API program or in the publications are cited; these test protocols may be different from those in the API test protocols hence, where that occurs, significant differences are noted.
particle size distribution (PSD) of relatively large dry solid additives for drilling fluids, especially lost circulation materials (LCMs). Detailed procedures for the utilization of any specific PSD method are not included. The technician should refer to and be guided by the measurement equipment manufacturer&#;s instructions. The particulates range in size from approximately one micron to as much as several millimeters in diameter, and are considered &#;granular&#; in shape, i.e. relatively isometric (of similar length, width, and height). The recommendations in this technical report generally are not applicable to the measurement of the PSD of nonisometric (high aspect ratio) materials such as fibers or flakes.
This document is not intended to be used for qualifying BOP shear rams or as a factory acceptance test (FAT) procedure.
Qualification and FAT of BOP shear rams is per API 16A.
This document is not intended to be used for qualifying BOP shear rams or as a factory acceptance test (FAT) procedure.
Qualification and FAT of BOP shear rams is per API 16A.
1.1.1 This technical report defines the methodology and test procedures necessary for the evaluation of polymeric materials suitable for use as the internal pressure sheath of an unbonded flexible pipes in high temperature applications. It describes the processes by which the critical material properties, both static and dynamic, can be measured and evaluated against relevant performance criteria.
1.1.2 This document relates primarily to the properties necessary for an internal pressure sheath required for oil and gas production. These are most relevant to high temperature applications. Only thermoplastic materials are considered for the internal pressure sheath. Elastomeric materials, which are used in bonded flexible pipes, are not considered in this document.
1.1.3 This document has the following format:
Section 1 Scope
Section 2 Referenced Documents
Section 3 Definitions and Acronyms
Section 4 Service Application&#;Background to selection of material tests used in the evaluation programme
Section 5 Evaluation Overview&#;The overall methodology employed in the evaluation of a candidate material
Section 6 Evaluation Test Programme&#;Presents, in detail, each of the material tests which form the material evaluation test programme
Section 7 Material Evaluation&#;Presents the criteria against which material test results should be compared and gives guidance on the interpretation of results.
Section 8 Bibliography
1.1.4 The following two applications of the Evaluation Standard are considered:
a. the evaluation of a candidate polymer for HT flexible pipe service,
b. the evaluation of a candidate polymer to determine its generic performance envelope/limits.
1.2 SIGNIFICANCE
1.2.1 This Evaluation Standard provides a procedure for determining whether candidate polymeric materials have the property levels necessary for successful use as the internal pressure sheath of an unbonded flexible pipe in high temperature high pressure applications.
1.2.2 For the purposes of this document, high temperatures are defined as those between 130 and 200°C. High pressure is considered to be at least 34.5 MPa ( psi).
1.2.3 This Evaluation Standard also provides a means for comparing the performance attributes of several potential pressure sheath materials for high temperature applications.
1.3 CURRENT STANDARDS
1.3.1 The current standards which relate to the evaluation of polymers for internal pressure sheath applications are:
i) API Specification 17J, &#;Specification for Unbonded Flexible Pipe,&#; First Edition [1],
ii) API Recommended Practice 17B &#;Recommended Practice for Flexible Pipe,&#; Second Edition [2].
1.3.2 These documents address all aspects of unbonded flexible pipe technology relevant to current levels of high temperature service; that is, to 130°C.
1.4 UNITS
Système International (SI) units are used in this evaluation standard. Imperial units may be given in brackets after the SI units.
1.5 SAFETY
The procedures described in this evaluation standard include materials tests requiring the use of high temperature and high pressure conditions, often with hostile chemicals. It is the responsibility of individuals or organisations using the standard to ensure that all appropriate safety procedures are implemented to prevent injuries to personnel and/or damage to equipment or facilities
This document is intended to be read in conjunction with API 17TR9 (under development), which highlights technical and commercial risks associated with high functionality umbilical terminations, the implications of decisions made early in the umbilical and SUT planning, selection and design phases, and provides guidance on specification and sizing of SUTs.
With guidance, owner/operators can avoid unexpected loading conditions and the resulting potential for equipment damage, failure, or leakage (either immediate or delayed leaks) or reduced service life.
This Document and the examples provided give the user guidance for evaluating subsea hydrotesting scenarios where test pressures are often well above maximum allowable operating pressure (MAOP).
There is a need for guidelines on the application of external pressure during the design, validation and operation of subsea equipment. Guidelines are also needed to calculate and/or determine a modification to the working pressure limits at the installed water depth, using the selected equipment API rated working pressure (RWP).
API Technical Report 17TR12 (hereafter API 17TR12) provides guidance for subsea equipment designers/manufacturers to properly account for external pressure (or in some cases, differential pressure) when designing and validating subsea equipment. Additionally, this technical report provides guidance to equipment purchaser/end-user to appropriately select rated equipment for their subsea systems with consideration to the effects of external pressure in addition to internal pressure, including differential pressure across a closure mechanism, and other applied mechanical or structural loads under all potential operating scenarios and functionality criteria.
NOTE API Technical Report 17TR4 (hereafter API 17TR4) provides additional information on the effects of external pressure on stresses generated within subsea equipment for the equipment designer.
API 17TR12 applies specifically to API SC17 equipment. API 17TR12 is to be used as a supplement to the equipment's applicable API product specification (e.g. API 6A, API 17D, API 17G), depending on its specific application, associated regulations, and project requirements. Other API product specifications may elect to adopt this technical report, subject to their component hardware, application-related design constraints and acceptance criteria. Specific subsea recommended practices, standards, and/or specifications may elect to adopt this technical report, also subject to their component hardware and application-related design constraints.
For this technical report, the term "equipment" also applies to the terms "part", "component", "sub-component" or "device" within a subsea system.
The objectives of this document are:
&#; to describe typical examples of the various subsystems and components that can be combined, in a variety of ways, to form complete subsea production systems;
&#; to describe the interfaces with typical downhole and topsides equipment that are relevant to subsea production systems;
&#; toprovide some basic design guidance on various aspects of subsea productionsystems.
This document provides comprehensive guidance on materials and pipe issues regarding the use and operation of PA-11 in flexible pipe applications, typically in production and gas handling applications up to 100ºC.
The document concentrates on the use of PA-11 in the internal sheath of flexible pipes, although similar considerations may also apply to other uses of PA-11 within flexibles, e.g., anti-wear layers, intermediate sheathes and outer sheathes.
The collective goal of this document is to prevent failure of the internal pressure sheath, as a result of ageing and associated loss of mechanical properties, by determining and disseminating the necessary scientific and practical information. API Specification 17J and Recommended Practice 17B(2,3) contain only limited information with respect to these phenomena, and this report supplements and updates the data in the Third Edition of API RP 17B(3).
PA-11 is also used in umbilicals. However, the exposure temperatures are frequently lower than production temperatures. In cases of higher temperature exposure, the information contained in this document applies.
This report documents the results of this study of the risks and benefits of additional penetrations in subsea wellheads below the BOP stack for the purpose of monitoring additional casing annuli for sustained casing pressure (SCP).
Additionally, it is intended to provide a high-level overview of issues that should be considered if a user elects to consider differential pressure in their design, especially in components with irregular geometry and with high stress concentrations. It is not intended to serve as a design specification. This document was prepared in response to a request from the API Subcommittee 17 (SC17).
Additionally, it is intended to provide a high-level overview of issues that should be considered if a user elects to consider differential pressure in their design, especially in components with irregular geometry and with high stress concentrations. It is not intended to serve as a design specification. This document was prepared in response to a request from the API Subcommittee 17 (SC17).
In the context of design, this covers not only installed subsea hardware (trees, manifolds, etc.), the connecting linkages (jumper arrangements, umbilical systems, etc.), but the fluids to be conveyed, initially from the fluid manufacturers&#; facilities through to bunkering at the host facility and, ultimately, injection or usage at remote subsea locations.
The guidelines set out the framework within which more detailed specifications and procedures should be developed to address the particular features of specific projects and specific installations in respect of design through to production operations and, ultimately, decommissioning. They also indicate what needs to be taken into account and approaches that can be considered, or may be taken, in order that blockages do not occur during the installation, commissioning and operations of a SPS.
It should be noted, however, that the inclusion of a particular approach identified in the document does not imply it is the only approach. Other approaches may be more suitable; this depends on the nature of the SPS and knowledge and experience of the system and fluid designers.
While the aim of this document is to prevent blockages in a SPS, it also addresses the issues of topside equipment which provides the control and chemical injection (CI) services necessary for the operation and performance of a SPS. The correct design of a SPS and the fluids to be utilized, and operation of the SPS including topside fluid bunkering, are critically important in avoiding blockages.
The document is intended for use by chemical suppliers to facilitate the provision of chemicals compatible with existing and intended subsea production systems (SPS) although it is envisaged that use of the document for specification purposes by the operators of such processes, will assist in ensuring the completeness of requests to supply.
The application of the document requires acceptance of the principle that it is the supplier&#;s responsibility to ensure that the chemicals supplied are fit for purpose and safe to use, although it is acknowledged that this responsibility can only be fulfilled if specification of requirements is complete. To this end the document identifies essential information that only SPS designers and operators can provide but without knowledge of which, suppliers should not supply. In the requirements of this document, responsibility for obtaining these items of critical information is placed upon the supplier, in the expectation that designers and operators will respond with their ready provision.
The functional performance of production chemicals is outside the scope of this document.
The assessments and tests specified in this document are not intended to qualify materials for use in an SPS in respect of pressure containment, mechanical load, cyclic mechanical load, or other design parameters.
The chemical-chemical compatibility of production chemicals at their respective application concentrations is also outside the scope of this document as is the effect of any incompatibility on their respective functional performance.
Finally, this document does not consider the health, safety, or environmental (HS&E) implications of deploying a production chemical in an SPS.
NOTE Attention is drawn to the fact that the tests specified in this document can generate data and information about the effect of a chemical/material incompatibility on the integrity of a material used in a SPS, that could necessitate additional testing, outside the scope of this document. Such additional testing should however be undertaken in order to ensure that all possible mechanisms that could threaten the integrity of a production, transportation, or chemical injection system are fully evaluated.
1) the completion of the well requires completion equipment or well control equipment assigned a pressure rating greater than 15,000 psia [15 ksi, 103.43 MPa] or a temperature rating greater than 350 °F (177 °C);
2) the maximum anticipated surface pressure including shut-in tubing pressure is greater than 15,000 psia [15 ksi, 103.43 MPa] on the seafloor for a well with a subsea wellhead or tied back to the surface and terminated with surface operated equipment; or
3) the flowing temperature is greater than 350 °F (177 °C) on the seafloor for a well with a subsea wellhead or tied back to the surface and terminated with surface operated equipment.
Service temperature ratings above 550 °F (288 °C) are outside the scope of this technical report.
This technical report is intended to serve as a general design guideline for HPHT application. Other subsea task groups and subcommittees may elect to adopt a portion or all of the presented guidelines for HPHT application, subject to their component hardware and application-related design constraints.
1) the completion of the well requires completion equipment or well control equipment assigned a pressure rating greater than 15,000 psia [15 ksi, 103.43 MPa] or a temperature rating greater than 350 °F (177 °C);
2) the maximum anticipated surface pressure including shut-in tubing pressure is greater than 15,000 psia [15 ksi, 103.43 MPa] on the seafloor for a well with a subsea wellhead or tied back to the surface and terminated with surface operated equipment; or
3) the flowing temperature is greater than 350 °F (177 °C) on the seafloor for a well with a subsea wellhead or tied back to the surface and terminated with surface operated equipment.
Service temperature ratings above 550 °F (288 °C) are outside the scope of this technical report.
This technical report is intended to serve as a general design guideline for HPHT application. Other subsea task groups and subcommittees may elect to adopt a portion or all of the presented guidelines for HPHT application, subject to their component hardware and application-related design constraints.
EditionThe scope of this technical report is to provide design guidelines for
oil and gas subsea equipment utilized in high-pressure high-temperature (HPHT) environments (refer to 3.1.16). For the purpose of the technical report, HPHT environments are intended to be one or a combination of the following well conditions:
1) the completion of
the well requires completion equipment or well control equipment assigned a pressure rating greater than 15,000 psia [15 ksi, 103.43 MPa] or a temperature rating greater than 350 °F (177 °C);
2) the maximum anticipated surface pressure including shut-in
tubing pressure is greater than 15,000 psia [15 ksi, 103.43 MPa] on the seafloor for a well with a subsea wellhead or tied back to the surface and terminated with surface operated equipment; or
3) the flowing temperature is greater than 350 °F (177 °C) on the
seafloor for a well with a subsea wellhead or tied back to the surface and terminated with surface operated equipment.
Service temperature ratings above 550 °F (288
°C) are outside the scope of this technical report.
This technical report
is intended to serve as a general design guideline for HPHT application. Other subsea task groups and subcommittees may elect to adopt a portion or all of the presented guidelines for HPHT application, subject to their component hardware and application-related design constraints.
oil and gas subsea equipment utilized in high-pressure high-temperature (HPHT) environments (refer to 3.1.16). For the purpose of the technical report, HPHT environments are intended to be one or a combination of the following well conditions:
1) the completion of
the well requires completion equipment or well control equipment assigned a pressure rating greater than 15,000 psia [15 ksi, 103.43 MPa] or a temperature rating greater than 350 °F (177 °C);
2) the maximum anticipated surface pressure including shut-in
tubing pressure is greater than 15,000 psia [15 ksi, 103.43 MPa] on the seafloor for a well with a subsea wellhead or tied back to the surface and terminated with surface operated equipment; or
3) the flowing temperature is greater than 350 °F (177 °C) on the
seafloor for a well with a subsea wellhead or tied back to the surface and terminated with surface operated equipment.
Service temperature ratings above 550 °F (288
°C) are outside the scope of this technical report.
This technical report
is intended to serve as a general design guideline for HPHT application. Other subsea task groups and subcommittees may elect to adopt a portion or all of the presented guidelines for HPHT application, subject to their component hardware and application-related design constraints.
While there are widely accepted codes and standards for the design of UTA and its subsystems, such as materials, core connector type, tubing specification, corrosion protection, and lifting arrangements, none of these standards specifically address the substantially increased risks incurred during packing, handling, and installing umbilicals with large UTAs.
The JIP deliverables are two API documents, API Technical Report 17TR9, Umbilical Termination Assembly (UTA) Selection and Sizing Recommendations, and API Technical Report 17TR10, Subsea Umbilical Termination (SUT) Design Recommendations.
NOTE API 17TR10 deals in more depth with umbilical and UTA installation and the differing style and restrictions of installation lay spread types.
While Q1, 9th was created independently of ISO :, the specification continues to satisfy those requirements and the supplemental requirements in API Q1, Eighth Edition (Q1, 8th). The formatting of Q1, 9th was revised to align with API Q2, First Edition and to follow a chronological order in the production and delivery of the product.
b) the maximum anticipated surface pressure or shut-in tubing pressure is greater than 15,000 psig on the seafloor for a well with a subsea wellhead or at the surface for a well with a surface wellhead; or
c) the flowing temperature is greater than 350 °F on the seafloor for a well with a subsea wellhead or on the surface for a well with a surface wellhead.
NOTE In high-temperature, low-pressure applications, not all methodologies presented in this document may apply.
The design verification process focuses on the analytical methods to achieve design verification by calculating the performance limits of a design (system, subsystems, and components), including its service life and material selection. The design validation process focuses on evaluating the potential failure modes of the equipment, the effects/consequences of the failures and defining the appropriate test methods to evaluate the reliability of the equipment against the identified failure modes including validation of material performance. The material section defines the required input parameters for the verification process and recommends the procedures necessary to evaluate the material fitness-for-service in the service environment. Functional testing procedures specific to HPHT equipment are also included in this document.
The design verification and validation protocols in this report should be used as a guide by the various API subcommittees to develop new and revised standards on equipment specifications for HPHT service. This report is not intended to replace existing API equipment specifications but to supplement them by illustrating accepted practices and principles that may be considered in order to maintain the safety and integrity of the equipment. This report is intended to apply to the following equipment: wellheads, tubing heads, tubulars, packers, connections, seals, seal assemblies, production trees, chokes, and well control equipment. It may be used for other equipment in HPHT service.
Annexes to this report provide additional information on the following:
&#; Annex A provides example HPHT material property data,
&#; Annex B is a compendium of published metallurgical-related field failures,
&#; Annex C provides a detailed explanation of the failure mode and effect analysis (FMEA) process,
&#; Annex D contains technical information on the considerations for the selection of castings and forgings, 2 API
&#; Annex E provides information on the important elements of a quality management system for manufacturers of HPHT equipment.
- 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;
- 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 API 5CT or ISO , API 5DP or ISO , and API 5L or ISO , 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 [CRS] 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, and so forth, 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 API 5CT or ISO , API 5DP or ISO , and API 5L or ISO 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 that 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 API 5CT or ISO , API 5DP or ISO , and API 5L or ISO . 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.
This technical report illustrates the equations and templates necessary to calculate the various pipe properties, including the following:
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 API 5CT or ISO , API 5DP or ISO , and API 5L or ISO , 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 [CRS] 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, and so forth, with the closest appropriate casing/tubing product. Similar caution should be exercised when using the performance equations for drill pipe or for collapse of cold-expanded API 5L pipe.
This technical report and the equations contained herein relate the input pipe manufacturing parameters in API 5CT or ISO , API 5DP or ISO , and API 5L or ISO 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 that 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 API 5CT or ISO , API 5DP or ISO , and API 5L or ISO . 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.
Torque-position is a precision assembly method that relies on a controlled process for successful implementation. When defined threading and assembly procedures are followed, the performance of the resulting assembled connection is optimized.
&#; bolt makeup (preload),
&#; internal pressure,
&#; tension, and
&#; bending moment.
All 69 flanges were analyzed with an axisymmetric finite element model for each of the four load cases. A postprocessor program was written to calculate the maximum moment capacity for various levels of pressure and tension, based on linear superposition of results. Three different criteria were used to establish the maximum moment, as follows.
a) ASME Section VIII, Division 2 allowable stress categories for the flange with the basic membrane stress allowable established by API.
b) Allowable bolt stresses as established by API.
c) Loss of preload on the ring joint. The results of this post-processing are presented in plots of pressure vs. allowable moment for various tension levels in Section 4.
There are several limitations to this work which should be understood. First, the effects of transverse shear or torsion were not considered in the analysis. Second, the results are for static loading only. No dynamic, fatigue, or fretting phenomena were considered in these results. Third, no thermal stresses or elevated temperature effects were considered for this technical report. Finally, these charts are not intended to replace a critical evaluation of any particular connection in an application where the charts show the flange to be marginal. The charts are intended to be used only as general guidelines for design.
Subsequent to the completion of this work, the 5 1/8 in. 15,000 psi flange was added to API 6A.This new flange was analyzed with the ABAQUS general-purpose finite-element system, using a half-symmetry three-dimensional model in order to find the same data as shown for the other flanges in this technical report.
Details of the analysis of the 5 1/8 in. 15,000 psi flange can be found in the report, &#;Finite Element Analysis of 5 1/8 in. ksi API 6BX Flange&#;, which was prepared for API by Stress Engineering Services. The report, SES Report Number PN, is dated February .
The results in this report are analytical and assume a temperature gradient across the flange as stated in this report. When the flange is insulated on the outside surface, the allowable loads will be higher.
Additional finite element models of five new flanges in API 6A, Sixteenth Edition, , which were not in the Fifteenth Edition, used as a basis for the earlier work, were developed for the combined loading of bolt makeup, internal pressure, tension and bending moment. The API materials were then grouped into four material categories. A thermal analysis was performed (using all 63 axisymmetric finite element models of PRAC 86-212 and the 5 new models) to determine the temperature gradient and resulting thermal stresses at steady state for all four material types at design bore temperatures of 350°F and 650°F.
The post-processor program of PRAC 86-21 (calculating the maximum moment capacity for various levels of pressure and tension based on superposition) was partly modified to include thermal effects and produce separate rating curves on the same chart, based on the leak or loss of preload (on the ring joint) criterion and the stress criteria. The stress criteria used were of two types: a) ASME Section VIII, Division 2, allowable stress categories for the flange with the basic membrane stress allowable established by APL and b) allowable bolt stresses as established by API. The results of this post-processing are presented in plots of pressure vs. allowable moment for various tension levels. These new rating charts were developed at two elevated temperatures for all four material categories in Appendices A, B, C, and D respectively.
See Section 4 for details of the axisymmetric analysis and Section 5 for details of the load capacity calculations.
As in the previous report PRAC 86-21, this report does not address the actual gasket contact loads required to make a seal. This report utilizes the leak or loss of preload (on the ring joint) criterion as in Bull 6AF (PRAC 86-21) and Bull 6AF2 (PRAC 88-21) and not the leakage criteria in report PN 90-21.7
Three-dimensional finite element meshes were generated for each of the 30, Type 6B, and Type 6BX flanges. The bending moment load case required a model of one quarter of the flange which was built up from the smaller segments and the half-bolt superelements. The computer program SESAM was used to obtain the stresses at selected critical flange and hub sections and to determine the gasket reaction due to each of the four unit load cases and the temperature difference load case. Leakage criterion was defined as the load combination which reduces the initial makeup compressive forces in the gasket to zero. The stresses in each defined section were linearized in accordance with the ASME Section VIII, Division 2, procedure to determine the membrane and membrane-plus-bending stress intensities. These stress intensities were checked against the allowables specified in API 6A, and the limiting loads were determined. A computer program LCCP was written to carry out this code check and a LOTUS 1-2-3 Release 3 worksheet was used to plot the load combination charts.
The results of the analysis carried out indicate that the leakage criterion governs the capacity of the smaller flanges in the Type 6B flanges. Leakage was governing for up to 9 in. size flanges in both the 52.5 ksi and 40 ksi makeups for the psi pressure. Leakage was governing the 5 1/8 in. for the higher pressures. Leakage was also found to be governing all Type 6BX flanges for working pressures of up to 5,000 psi. For the 10,000 psi and 15,000 psi flanges, leakage governed only in the larger size range greater than 2 9/16 in. Leakage was governing in all the 20,000 psi API 6BX flanges. The leakage model adopted in this study employs several approximations that have not yet been evaluated. Therefore, the actual leakage forces, i.e. load combinations leading to leakage, may be considerably higher than assumed herein. In reality, the gasket only leaks when its energized capacity is exceeded.
The state of stress at the stress governing hub section under the combined loading of makeup, pressure, tension and bending moment is considered to be &#;secondary.&#; However, when pressure, tension, and bending moments are applied together with the necessary makeup to resist these actions without leakage, the state of stress is rendered &#;primary&#; and, therefore, the allowable stress intensities are halved. This does not seem to be consistent, and it may by far exceed the intention of the code. However, the oversight subcommittee preferred to adopt the conservative route, which may be overly conservative pending further evaluation. Therefore, it may be concluded that when the hub stresses are treated as primary, most flanges do not possess significant reserve strength beyond the leakage condition. In fact, if the leakage condition was somewhat conservative, the stress condition may become governing for most flanges.
The temperature difference of 250°F internal and 30°F external leads to increases in the load-carrying capacity of the flanges. This condition is caused by the compressive forces generated in the gasket due to this temperature difference, and the increase in the allowable stresses when the self-limiting temperature load condition is included. It is recommended that a 3-D finite element, nonlinear material and geometric models of approximately eight flanges be carried out to determine the actual failure mechanism that governs the behavior of these flanges. This includes the prediction of the response of the gasket under increasing load and a more accurate definition of the leakage mechanism. The elimination of the raised face does not significantly reduce the stresses in the hub which caused six Type 6B flanges to fail to meet the ASME criterion for makeup load only (52.5 ksi for 105 ksi bolting). The stress intensities were reduced only by about 5% when the raised face was eliminated, increasing the thickness of the flange by about 10%. The hub thickness for these flanges had to be increased by up to about 27% of their existing thicknesses together with the elimination of the raised face.
The bolt stresses did not govern for any of the flanges analyzed. Bolt stresses are typically within approximately 67% of their yield strength due to makeup, pressure, tension, and bending moment loads. The bolts are expected to be made up to half their yield. The stresses in the bolts due to temperature differences increase by about 5 ksi to 7 ksi, which is about 6% to 8% of the bolt yield stress. The other load conditions (pressure, tension, and bending moments) increase bolt stress by twice the increase due to the temperature difference. Therefore, it is concluded that the bolts will not approach their limiting criterion under the investigated load conditions.
Three-dimensional finite element meshes were generated for the Type 6B, and Type 6BX flanges. The bending moment load case required a model of one quarter of the flange which was built up from the smaller segments and the half-bolt super elements. The computer program SESAM was used to obtain the stresses at selected critical flange and hub sections and to determine the gasket reaction due to each of the four unit load cases and the temperature difference load case. Leakage criterion was defined as the load combination which reduces the initial makeup compressive forces in the gasket to zero. The stresses in each defined section were linearized in accordance with the ASME Section VIII, Division 2, procedure to determine the membrane and membrane-plus-bending stress intensities. These stress intensities were checked against the allow ables specified in API 6A, and the limiting loads were determined. A computer program LCCP was written to carry out this code check and a LOTUS 1-2-3 Release 3 worksheet was used to plot the load combination charts.
The results of the analysis carried out indicate that the leakage criterion governs the capacity of the smaller flanges in the Type 6B flanges. Leakage was governing for up to 9 in. size flanges in both the 52.5 ksi and 40 ksi make ups for the psi pressure. Leakage was governing the 5 1/8 in. for the higher pressures. Leakage was also found to be governing all Type 6BX flanges for working pressures of up to 5,000 psi. For the 10,000 psi and 15,000 psi flanges, leakage governed only in the larger size range greater than 2 9/16 in. Leakage was governing in all the 20,000 psi API 6BX flanges. The leakage model adopted in this study employs several approximations that have not yet been evaluated. Therefore, the actual leakage forces, i.e. load combinations leading to leakage, may be considerably higher than assumed herein. In reality, the gasket only leaks when its energized capacity is exceeded.
The state of stress at the stress governing hub section under the combined loading of makeup, pressure, tension and bending moment is considered to be "secondary." However, when pressure, tension, and bending moments are applied together with the necessary makeup to resist these actions without leakage, the state of stress is rendered "primary" and, therefore, the allowable stress intensities are halved. This does not seem to be consistent, and it may by far exceed the intention of the code. However, the oversight subcommittee preferred to adopt the conservative route, which may be overly conservative pending further evaluation. Therefore, it may be concluded that when the hub stresses are treated as primary, most flanges do not possess significant reserve strength beyond the leakage condition. In fact, if the leakage condition was somewhat conservative, the stress condition may become governing for most flanges.
The temperature difference of 250 °F internal and 30 °F external leads to increases in the load-carrying capacity of the flanges. This condition is caused by the compressive forces generated in the gasket due to this temperature difference, and the increase in the allowable stresses when the self-limiting temperature load condition is included. It is recommended that a 3-D finite element, nonlinear material and geometric models of approximately eight flanges be carried out to determine the actual failure mechanism that governs the behavior of these flanges. This includes the prediction of the response of the gasket under increasing load and a more accurate definition of the leakage mechanism. The elimination of the raised face does not significantly reduce the stresses in the hub which caused six Type 6B flanges to fail to meet the ASME criterion for makeup load only (52.5 ksi for 105 ksi bolting). The stress intensities were reduced only by about 5 % when the raised face was eliminated, increasing the thickness of the flange by about 10 %. The hub thickness for these flanges had to be increased by up to about 27 % of their existing thicknesses together with the elimination of the raised face.
The bolt stresses did not govern for any of the flanges analyzed. Bolt stresses are typically within approximately 67 % of their yield strength due to makeup, pressure, tension, and bending moment loads. The bolts are expected to be made up to half their yield. The stresses in the bolts due to temperature differences increase by about 5 ksi to 7 ksi, which is about 6 % to 8 % of the bolt yield stress. The other load conditions (pressure, tension, and bending moments) increase bolt stress by twice the increase due to the temperature difference. Therefore, it is concluded that the bolts will not approach their limiting criterion under the investigated load conditions.
Three-dimensional finite element meshes were generated for the Type 6B, and Type 6BX flanges. The bending moment load case required a model of one quarter of the flange which was built up from the smaller segments and the half-bolt super elements. The computer program SESAM was used to obtain the stresses at selected critical flange and hub sections and to determine the gasket reaction due to each of the four unit load cases and the temperature difference load case. Leakage criterion was defined as the load combination which reduces the initial makeup compressive forces in the gasket to zero. The stresses in each defined section were linearized in accordance with the ASME Section VIII, Division 2, procedure to determine the membrane and membrane-plus-bending stress intensities. These stress intensities were checked against the allow ables specified in API 6A, and the limiting loads were determined. A computer program LCCP was written to carry out this code check and a LOTUS 1-2-3 Release 3 worksheet was used to plot the load combination charts.
The results of the analysis carried out indicate that the leakage criterion governs the capacity of the smaller flanges in the Type 6B flanges. Leakage was governing for up to 9 in. size flanges in both the 52.5 ksi and 40 ksi make ups for the psi pressure. Leakage was governing the 5 1/8 in. for the higher pressures. Leakage was also found to be governing all Type 6BX flanges for working pressures of up to 5,000 psi. For the 10,000 psi and 15,000 psi flanges, leakage governed only in the larger size range greater than 2 9/16 in. Leakage was governing in all the 20,000 psi API 6BX flanges. The leakage model adopted in this study employs several approximations that have not yet been evaluated. Therefore, the actual leakage forces, i.e. load combinations leading to leakage, may be considerably higher than assumed herein. In reality, the gasket only leaks when its energized capacity is exceeded.
The state of stress at the stress governing hub section under the combined loading of makeup, pressure, tension and bending moment is considered to be "secondary." However, when pressure, tension, and bending moments are applied together with the necessary makeup to resist these actions without leakage, the state of stress is rendered "primary" and, therefore, the allowable stress intensities are halved. This does not seem to be consistent, and it may by far exceed the intention of the code. However, the oversight subcommittee preferred to adopt the conservative route, which may be overly conservative pending further evaluation. Therefore, it may be concluded that when the hub stresses are treated as primary, most flanges do not possess significant reserve strength beyond the leakage condition. In fact, if the leakage condition was somewhat conservative, the stress condition may become governing for most flanges.
The temperature difference of 250 °F internal and 30 °F external leads to increases in the load-carrying capacity of the flanges. This condition is caused by the compressive forces generated in the gasket due to this temperature difference, and the increase in the allowable stresses when the self-limiting temperature load condition is included. It is recommended that a 3-D finite element, nonlinear material and geometric models of approximately eight flanges be carried out to determine the actual failure mechanism that governs the behavior of these flanges. This includes the prediction of the response of the gasket under increasing load and a more accurate definition of the leakage mechanism. The elimination of the raised face does not significantly reduce the stresses in the hub which caused six Type 6B flanges to fail to meet the ASME criterion for makeup load only (52.5 ksi for 105 ksi bolting). The stress intensities were reduced only by about 5 % when the raised face was eliminated, increasing the thickness of the flange by about 10 %. The hub thickness for these flanges had to be increased by up to about 27 % of their existing thicknesses together with the elimination of the raised face.
The bolt stresses did not govern for any of the flanges analyzed. Bolt stresses are typically within approximately 67 % of their yield strength due to makeup, pressure, tension, and bending moment loads. The bolts are expected to be made up to half their yield. The stresses in the bolts due to temperature differences increase by about 5 ksi to 7 ksi, which is about 6 % to 8 % of the bolt yield stress. The other load conditions (pressure, tension, and bending moments) increase bolt stress by twice the increase due to the temperature difference. Therefore, it is concluded that the bolts will not approach their limiting criterion under the investigated load conditions.
The July 30, , API Subcommittee Meeting Minutes contained the Material Toughness Task Group Charge. It comprised Attachment 6. The charge(s) were:
1. Evaluate the material toughness requirements for API Specification 6A materials, for acceptance worldwide.
2. Perform a survey of the industry and review literature for material toughness values based on technical data and design requirements.
3. Devise a method or action to resolve difference between the European and U.S. opinions on material toughness.
4. Establish work groups to prepare appropriate revisions to API Specification 6A for ballot by June .
1.2 AMENDED TASK GROUP CHARGE
The Task Group came to several conclusions based on the charges:
Charge 1: The Task Group could not evaluate worldwide parameters necessary for acceptance of API Specification6A materials toughness requirements. The justification for other groups Õ requirements was not readily obvious.
Charge 2: The members of the Task Group comprised across section of industry users and manufacturers which have worldwide exposure. The Task Group could not document any materials related failures on equipment whose materials had met the API Specification 6A requirement of15 ft-lb. All documentable failures did not meet the existing requirements. A literature survey revealed no technical data or design requirements which are relatable to API Specification 6A equipment design or usage.
Charge 3: The differences between U.S. and European opinions on material toughness relate directly to a difference in philosophy. There are several differences, but the major difference is that the Europeans feel that the Charpy value relates to design while the U.S. opinion is that the Charpy test is a quality assurance exercise in sorting out Òrogue materials.
Unfortunately, the technical justification of either of the requirements is unclear. The historical evidence indicates that both approaches are conservative since no API Specification 6A equipment failures have been attributed to brittle materials which met the requirements of the existing standards.
Therefore, the Task Group decided to start with a clean sheet and adopted the charge to Determine what is neces-sary to prevent brittle fracture in the field.
Charge 4: With this charge in mind, the Task Group established work groups for:
a. Literature survey.
b. Literature evaluation.
c. Correlations and calculations.
d. Position paper containing proposed changes.
Since end connections usually are included in these tests, they become potential failure points for a &#;re-tested valve assembly. Since end connections are standard products, API has sponsored several research projects to de&#;ne the ability of end connections to pass the &#;re test. Ten standard end con-nections of various sizes, types, and pressure ratings weretested in (2). (PRAC-)
Two subsequent research projects (3, 4) in &#;81(PRAC 80-33) and &#;82 (PRAC 81-33) resulted in procedures to analytically predict the performance of &#;angedand clamped connections to the &#;reenvironment.
This procedure basically is composed of four parts: (a)predicting the temperature distribution in the &#;ange, (b) predicting the preload loss, (c) predicting the performance of the various seals with the reduced preloads which occur in a &#;re,and (d) predicting whether or not yielding of bolts is likely to occur. Signi&#;cant yielding will lead to leakage either during the &#;re or shortly afterward.
A fourth project (PRAC-83-33) (5) evaluated the standard end connections in API Speci&#;cations 6A (6) and 6D (7)using these analytical procedures.
This report summarizes the results of all the projects. In addition, the appendixes present the analytical procedures used to generate the performance prediction of section 3.
Innumerable factors contribute to flange failures under fire conditions, so it is difficult to formulate hard and fast engineering rules which will ensure fire resistant behavior under all circumstances. It is possible to formulate a generalized methodology to examine enhancements which will increase the probability of survival of API flanges under fire conditions.
1.1 COMPARATIVE TESTING
To provide a basis for comparing protection methods it is necessary to provide consistent testing criteria. Although primarily used for valves, API RP 6F and API Spec 6FA, as well as other test procedures, listed in the following, have been used for testing connection and seal performances.
a. API RP 6F.
b. API Spec 6FA (supersedes API RP 6F).
c. User Modified API RP 6F, (Appendix A).
d. API Spec 6FB&#;Should be considered as the standard test method.
It is not intended that the order of listing indicates test severity.
a. Temperature&#;steady state or a high and low range of service.
b. Fluids and gases&#;stagnant or flowing.
c. Pressure&#;continuous or a low and high range.
d. Chemicals and additives&#;inhibitors, descalers, acidizing, etc.
e. Mechanical requirements&#;dynamic or static, torque, setting force.
f. Failure criteria&#;pressure leakage, loss of mechanical function, inability to set or retrieve.
Alloy candidates were recommended by AWHEM membership for analysis and confirmed by API's approval of New Work Item No. - in June . Several material suppliers and several AWHEM member companies donated material for testing. Metallurgists on the Task Group screened material certificates to ensure a "normal" chemistry without enhancements for the material candidates listed in Table 1, Table 2, and Table 3.
Alloy chemistries from the material certificates for each of the supplied alloy candidates are provided in Table 6 through Table 16, located at the end of this report for readability.
Alloy candidates were recommended by AWHEM membership for analysis and confirmed by API&#;s approval of New Work Item No. - in June . Several material suppliers and several AWHEM member companies donated material for testing. Metallurgists on the task group screened material certificates to ensure a &#;normal&#; chemistry without enhancements for the material candidates listed in Table 1, Table 2, and Table 3.
The success of an FRMS depends on the willingness of diverse stakeholders to alter their behaviors and practices to help mitigate fatigue risk. It is important to bring employees, supervisors and managers early into the process of designing an FRMS. Doing so helps create a buy-in so that they will support and own the FRMS because of the benefits they see for themselves as well as for the overall safety of the workplace.
This recommended practice was developed for refineries, petrochemical and chemical operations, natural gas liquefaction plants, and other facilities such as those covered by the OSHA Process Safety Management Standard, 29 CFR .119
RP 755 was specifically developed for US facilities operating under the OSHA Process Safety Management Standard. Companies voluntarily may also choose to take advantage of RP 755 to design and implement FRMS across their other operations, including upstream and international operations outside the US where fatigue risk can also significantly impact the operational safety. However, doing so is not required under RP 755.
Applies to a workforce that is commuting daily to a job location
RP 755 is specifically designed for employees who live and sleep at their homes during off-duty hours and have normal family-social interactions on a daily basis. These recommendations are not designed for employees who travel to remote locations (e.g. offshore platforms or onshore remote locations) where they live in company-provided accommodations and are isolated from their normal daily family and social interactions.
Research on sleep patterns in offshore platforms and other remote locations shows a greater capacity to adapt to longer sequences of consecutive workdays and maintain adequate sleep when the demands of family and social interactions are not competing with sleep and relaxation time.[2,3]
BakerRisk designed and constructed the Deflagration Load Generator (DLG) test rig used for these tests. The test rig measures 48 ft. long by 24 ft. deep by 12 ft. tall and has three rigid walls, a rigid roof and floor, and one open wall facing the structure being tested, as shown in Figure 1. The interior of the rig is fitted with congestion. The test rig is filled with a propane/air mixture and ignited, causing a VCE.
The specific test environment is controlled through selection of fuel concentration, obstacle geometry, and the distance between the test article and the VCE test rig. The tests were deflagrations with moderate flame speeds such that the wave shape of the blast load would include a rise time to the peak pressure. This type of VCE is representative of typical accidental VCEs at industrial facilities.
The VCE deflagrations are set to vent outside the test rig, toward the test articles. The tents were placed at a sufficient range from the test rig such that three test articles could be tested simultaneously on each shot. The test rig was configured such that the blast loading on the tent could be changed by varying the fuel concentration rather than relocating the test articles.
The tests were originally designed to serve multiple purposes:
&#; Provide data on response of tents to a variety of blast loads ranging from 0.6 to 1.5 psi,
&#; Identify the failure modes for different types of tents, and
&#; Obtain data on tent response to support estimates on the vulnerability of tent occupants.
As the testing was performed it became apparent that the tents being tested could withstand higher pressures than originally envisioned. The test program was therefore modified to accommodate the observed behavior. The development and modifications to the scope of the test program are discussed in Section 2 of this report. The following three series of tests were conducted.
&#; A Series &#; Three types of non-wind rated tents were tested with the long side of the tents facing the blast source. The results of this series of tests are presented in Section 3.
&#; B Series &#; The same types of tents were rotated 90 degrees and retested at higher loads. The results of this series of tests are presented in Section 4.
&#; C Series &#; Three types of engineered tents (designed for 90 mph 3 second wind gusts) were tested at two different pressures. The results of this series of tests are presented in Section 5.
Subsequent to the completion of the API funded tests BakerRisk performed two additional tests to evaluate the DLG performance as internal research. The response of the tents in these internal research tests, including the response of contents added to the tents, is discussed in Section 6.
The Explosion Research Cooperative (ERC) participants voted to release the data from a series of shock tube tests performed under their sponsorship that addressed the potential for the contents of a tent to become airborne. The data, in term of object mass and velocity, are provided in Section 7.
This report presents data only and does not provide any summary or conclusions on the acceptability of a tent siting approach.
It is not the intent of this technical report to explain the benefits of thread root rolling, but the manufacturing process and quality control requirements. This technical report will address the best practices (or recommended practices) to cold root roll API 7-2 threads and identification marking.
This technical report will not address cold root rolling using manual lathes (CW/Manual)&#;a similar process but with different tools used for the pin and box. However, the tools described in this technical report can also be used on manual lathes. The steps to position the CW roll into the thread and the paths the tools move can vary between CNC machines controls.
This manual is under jurisdiction of the Executive Committee on Training and Development, Exploring & Production Department, American petroleum institute. It is intended to familiarize operating personnel with the use of gas lift as an artificial lift system. It includes information on the basic principles of gas lift, the choice of gas lift equipment, and how various types of gas equipment work, and how a gas system should be designed. Information also included on monitoring, adjusting, regulating, and trouble-shooting gas lift equipment.
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