CEN/TC 12 - Materials, equipment and offshore structures for petroleum and natural gas industries

This document contains requirements for defining the seismic design procedures and criteria for offshore structures; guidance on the requirements is included in Annex A. The requirements focus on fixed steel offshore structures and fixed concrete offshore structures. The effects of seismic events on floating structures and partially buoyant structures are briefly discussed. The site-specific assessment of jack-ups in elevated condition is only covered in this document to the extent that the requirements are applicable.
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:
a) seismic design procedures which are dependent on the exposure level of the offshore structure and the expected intensity of seismic events;
b) 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 abnormal limit state (ALS) to ensure that it meets reserve strength and energy dissipation requirements.
Procedures and requirements for a site-specific probabilistic seismic hazard analysis (PSHA) are addressed for offshore structures in high seismic areas and/or with high exposure levels. However, a thorough explanation of PSHA procedures is not included.
Where a simplified design approach is allowed, worldwide offshore maps, which are included in Annex B, show the intensity of ground shaking corresponding to a return period of 1 000 years. In such cases, these maps can be used with corresponding scale factors to determine appropriate seismic actions for the design of a structure, unless more detailed information is available from local code or site-specific study.
NOTE      For design of fixed steel offshore structures, further specific requirements and recommended values of design parameters (e.g. partial action and resistance factors) are included in ISO 19902, while those for fixed concrete offshore structures are contained in ISO 19903. Seismic requirements for floating structures are contained in ISO 19904, for site-specific assessment of jack-ups and other MOUs in the ISO 19905 series, for arctic structures in ISO 19906 and for topsides structures in ISO 19901‑3.

This document specifies the requirements and recommendations for the design, setting depth and installation of conductors for the offshore petroleum and natural gas industries. This document specifically addresses:
—    design of the conductor, i.e. determination of the diameter, wall thickness, and steel grade;
—    determination of the setting depth for three installation methods, namely, driving, drilling and cementing, and jetting;
—    requirements for the three installation methods, including applicability, procedures, and documentation and quality control.
This document is applicable to:
—    platform conductors: installed through a guide hole in the platform drill floor and then through guides attached to the jacket at intervals through the water column to support the conductor, withstand actions, and prevent excessive displacements;
—    jack-up supported conductors: a temporary conductor used only during drilling operations, which is installed by a jack-up drilling rig. In some cases, the conductor is tensioned by tensioners attached to the drilling rig;
—    free-standing conductors: a self-supporting conductor in cantilever mode installed in shallow water, typically water depths of about 10 m to 20 m. It provides sole support for the well and sometimes supports a small access deck and boat landing;
—    subsea wellhead conductors: a fully submerged conductor extending only a few metres above the sea floor to which a BOP and drilling riser are attached. The drilling riser is connected to a floating drilling rig. The BOP, riser and rig are subject to wave and current actions while the riser can also be subject to VIV.
This document is not applicable to the design of drilling risers.

This document specifies requirements and recommendations for the site-specific assessment of mobile floating units for use in the petroleum and natural gas industries. It addresses the installed phase, at a specific site, of manned non-evacuated, manned evacuated and unmanned mobile floating units.
This document addresses mobile floating units that are monohull (e.g. ship-shaped vessels or barges); column-stabilized, commonly referred to as semi-submersibles; or other hull forms (e.g. cylindrical/conical shaped). It is not applicable to tension leg platforms. Stationkeeping can be provided by a mooring system, a thruster assisted mooring system, or dynamic positioning. The function of the unit can be broad, including drilling, floatel, tender assist, etc. In situations where hydrocarbons are being produced, there can be additional requirements.
This document does not address all site considerations, and certain specific locations can require additional assessment.
This document is applicable only to mobile floating units that are structurally sound and adequately maintained, which is normally demonstrated through holding a valid RCS classification certificate.
This document does not address design, transportation to and from site, or installation and removal from site.
This document sets out the requirements for site-specific assessments, but generally relies on other documents to supply the details of how the assessments are to be undertaken. In general:
—     ISO 19901‑7 is referenced for the assessment of the stationkeeping system;
—     ISO 19904‑1 is referenced to determine the effects of the metocean actions on the unit;
—     ISO 19906 is referenced for arctic and cold regions;
—     the hull structure and air gap are assessed by use of a comparison between the site-specific metocean conditions and its design conditions, as set out in the RCS approved operations manual;
—     ISO 13624‑1 and ISO/TR 13624‑2[1] are referenced for the assessment of the marine drilling riser of mobile floating drilling units. Equivalent alternative methodologies can be used;
—     IMCA M 220 is referenced for developing an activity specific operating guidelines. Agreed alternative methodologies can be used.
NOTE    RCS rules and the IMO MODU code[13] provide guidance for design and general operation of mobile floating units.

This document covers the physical properties, potential contaminants and test procedures for heavy brine fluids manufactured for use in oil and gas well drilling, completion, and workover fluids.
This document supplements API RP 13J, 5th edition (2014), the requirements of which are applicable with the exceptions specified in this document.
This document provides more suitable method descriptions for determining the formate brines pH, carbonate/bicarbonate concentrations and crystallization temperature at ambient pressure compared to the methods provided by API RP 13J, 5th edition (2014).
This document is intended for the use of manufacturers, service companies and end-users of heavy brines.

This document specifies the requirements for design including shape and dimensions, material as well as strength for pipe support. Applicable pipe size range varies depending on support types. This document covers topside systems for fixed or floating offshore oil and gas projects. This document is applicable to design temperature of support within the range between –46 °C up to 200 °C.
This document is limited to metallic pipes, covering the following pipe supports:
—    clamped shoe;
—    welded shoe;
—    U-bolt;
—    U-strap;
—    bracing for branch connection;
—    trunnion and stanchion;
—    guide support (guide, hold-down, guide and hold-down, line stop).

This document specifies the requirements for the procedures and design criteria used for calculating the required wall thickness of new tubes and associated component fittings for petroleum, petrochemical and natural gas industries. These procedures are appropriate for designing tubes for service in both corrosive and non-corrosive applications. These procedures have been developed specifically for the design of refinery and related process-fired heater tubes (direct-fired, heat-absorbing tubes within enclosures). These procedures are not intended to be used for the design of external piping.
This document does not give recommendations for tube retirement thickness. A technique for estimating the life remaining for a heater tube is described
This document is a supplement to API 530, 7th edition (2015) including addendum 1 and addendum 2, the requirements of which are applicable with the exceptions specified in this document.

This document specifies 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 document does not apply to field use or field testing.
This document does not apply to repair of wellhead and tree equipment except for weld repair in conjunction with manufacturing.
This document does not apply to tools used for installation and service (e.g. running tools, test tools, wash tools, wear bushings, and lubricators).
This document supplements API Spec 6A, 21st edition (2018), the requirements of which are applicable with the exceptions specified in this document.

This document gives general principles, specifies requirements and gives recommendations for the assessment of the stability of non-metallic materials for service in equipment used in oil and gas exploration and production environments. This information aids in material selection. It can be applied to help avoid costly degradation failures of the equipment itself, which could pose a risk to the health and safety of the public and personnel or the environment. This document also provides guidance for quality assurance. It supplements but does not replace, the material requirements given in the appropriate design codes, standards or regulations.
This document addresses the resistance of thermoplastics to the deterioration in properties that can be caused by physical or chemical interaction with produced and injected oil and gas-field media, and with chemical treatment. Interaction with sunlight and ionizing radiation are excluded from the scope of this document.
This document is not necessarily suitable for application to equipment used in refining or downstream processes and equipment.
The equipment considered includes, but is not limited to, non-metallic pipelines, piping, liners, seals, gaskets and washers.
Blistering by rapid gas decompression is not included in the scope of this document.
This document applies to the assessment of the stability of non-metallic materials in simulated hydrocarbon production conditions to aid the selection of materials for equipment designed and constructed using conventional design criteria. Designs utilizing other criteria are excluded from its scope.

This document provides requirements and guidelines for marine geophysical investigations. It is applicable to operators/end users, contractors and public and regulatory authorities concerned with marine site investigations for offshore structures for petroleum and natural gas industries.
This document provides requirements, specifications, and guidance for:
a)   objectives, planning, and quality management;
b)   positioning;
c)   seafloor mapping, including instrumentation and acquisition parameters, acquisition methods, and deliverables;
d)   sub-seafloor mapping, including seismic instrumentation and acquisition parameters, and non-seismic-reflection methods;
e)   reporting;
f)    data integration, interpretation, and investigation of geohazards.
This document is applicable to investigation of the seafloor and the sub-seafloor, from shallow coastal waters to water depths of 3 000 m and more. It provides guidance for the integration of the results from marine soil investigations and marine geophysical investigations with other relevant datasets.
NOTE 1 The depth of interest for sub-seafloor mapping depends on the objectives of the investigation. For offshore construction, the depths of investigation are typically in the range 1 m below seafloor to 200 m below seafloor. Some methods for sub-seafloor mapping can also achieve much greater investigation depths, for example for assessing geohazards for hydrocarbon well drilling.
There is a fundamental difference between seafloor mapping and sub-seafloor mapping: seafloor signal resolution can be specified, while sub-seafloor signal resolution and penetration cannot. This document therefore contains requirements for the use of certain techniques for certain types of seafloor mapping and sub-seafloor mapping (similarly, requirements are given for certain aspects of data processing). If other techniques can be shown to obtain the same information, with the same or better resolution and accuracy, then those techniques may be used.
Mapping of pre-drilling well-site geohazards beneath the seafloor is part of the scope of this document.
NOTE 2 This implies depths of investigation that are typically 200 m below the first pressure-containment casing string or 1 000 m below the seafloor, whichever is greatest. Mapping of pre-drilling well-site geohazards is therefore the deepest type of investigation covered by this document.
In this document, positioning information relates only to the positioning of survey platforms, sources and receivers. The processes used to determine positions of seafloor and sub-seafloor data points are not covered in this document.
Guidance only is given in this document for the use of marine shear waves (A.8.3.3), marine surface waves (A.8.3.4), electrical resistivity imaging (A.8.3.5) and electromagnetic imaging (A.8.3.6).

This document specifies requirements for managing and controlling the weight and centre of gravity (CoG) of offshore facilities by means of mass management during all lifecycle phases including; conceptual design, front end engineering design (FEED), detail engineering, construction and operations. These can be new facilities (greenfield) or modifications to existing facilities (brownfield).
Weight management is necessary throughout operations, decommissioning and removal to facilitate structural integrity management (SIM). The provisions of this document are applicable to fixed and floating facilities of all types.
Weight management only includes items with static mass.
Snow and ice loads are excluded as they are not considered to be part of the facility. Dynamic loads are addressed in ISO 19904-1, ISO 19901-6 and ISO 19901-7.
This document specifies:
a) requirements for managing and controlling weights and CoGs of assemblies and entire facilities;
b) requirements for managing weight and CoG interfaces;
c) standardized terminology for weight and CoG estimating and reporting;
d) requirements for determining not-to-exceed (NTE) weights and budget weights;
e) requirements for weighing and determination of weight and centre of gravity (CoG) of tagged equipment, assemblies, modules and facilities;
This document can be used:
f) as a basis for costing, scheduling or determining suitable construction method(s) or location(s) and installation strategy;
g) as a basis for planning, evaluating and preparing a weight management plan and reporting system;
h) as a contract reference;
i) as a means of refining the structural analysis or model.

This document is applicable to dry gas sealing systems for axial, centrifugal, and rotary screw compressors and expanders as described in ISO 10439 (all parts), ISO 10440-1 and ISO 10440-2. Although intended for use primarily in oil refineries, it is also applicable to petrochemical facilities, gas plants, liquefied natural gas (LNG) facilities and oil and gas production facilities. The information provided is designed to aid in the selection of the system that is most appropriate for the risks and circumstances involved in various installations.
This document does not apply to other types of shaft seals such as clearance seals, restrictive ring seals or oil seals.
This document is a supplement to API Std 692, 1st edition (2018), the requirements of which are applicable with the exceptions specified in this document.

This document establishes the principles, specifies the requirements and provides guidance for the development and implementation of an escape, evacuation and rescue (EER) plan. It is applicable to offshore installation design, construction, transportation, installation, offshore production/exploration drilling operation service life inspection/repair, decommissioning and removal activities related to petroleum and natural gas industries in the arctic and cold regions.
Reference to arctic and cold regions in this document is deemed to include both the Arctic and other locations characterized by low ambient temperatures and the presence or possibility of sea ice, icebergs, icing conditions, persistent snow cover and/or permafrost.
This document contains requirements for the design, operation, maintenance, and service-life inspection or repair of new installations and structures, and to modification of existing installations for operation in the offshore Arctic and cold regions, where ice can be present for at least a portion of the year. This includes offshore exploration, production and accommodation units utilized for such activities. To a limited extent, this document also addresses the vessels that support ER, if part of the overall EER plan.
While this document does not apply specifically to mobile offshore drilling units (MODUs, see ISO 19905‑1) many of the EER provisions contained herein are applicable to the assessment of such units in situations when the MODU is operated in arctic and cold regions.
The provisions of this document are intended to be used by stakeholders including designers, operators and duty holders. In some cases, floating platforms (as a type of offshore installations) can be classified as vessels (ships) by national law and the EER for these units are stipulated by international maritime law. However, many of the EER provisions contained in this document are applicable to such floating platforms.
This document applies to mechanical, process and electrical equipment or any specialized process equipment associated with offshore arctic and cold region operations that impacts the performance of the EER system. This includes periodic training and drills, EER system maintenance and precautionary down-manning as well as emergency situations.
EER associated with onshore arctic oil and gas facilities are not addressed in this document, except where relevant to an offshore development.

This document provides requirements and guidance for reporting of production performance data and production loss data in the operating phase by use of production loss categorization. It supplements the principles of ISO 20815:2018, Clause E.3 and Annex G by providing additional details.
This document focusses on installations and asset elements within the upstream business category. Business categories and associated installations and plants/units, systems and equipment classes are used in line with ISO 14224:2016, Annex A.
The production loss categories given in Annex A are given at a high taxonomic level and supplements the reporting of failure and maintenance parameters as defined in ISO 14224:2016, Annex B.

This document specifies the selection criteria and minimum requirements for protective coating systems for maintenance and field repair of risers exposed to conditions in the splash zone. It is applicable for maintenance requirements and field repairs of riser coatings.
This document does not apply to the selection of techniques and materials used to restore integrity of the risers to be coated, nor does it apply to the selection of additional mechanical protective materials that are not part of the coating systems described in this document.
New construction shop applied riser coatings are covered in ISO 18797-1. Compatible maintenance and repair coating systems specified in ISO 18797-1 are covered in this document.

This document specifies the technical delivery conditions for steel pipes (casing, tubing and pup joints), coupling stock, coupling material and accessory material.
By agreement between the purchaser and manufacturer, this document can also be applied to other plain-end pipe sizes and wall thicknesses.
This document is applicable to the following connections:
—     short round thread casing (SC);
—     long round thread casing (LC);
—     buttress thread casing (BC);
—     non-upset tubing (NU);
—     external upset tubing (EU);
—     integral-joint tubing (IJ).
NOTE 1  For further information, see API Spec 5B.
For such connections, this document specifies the technical delivery conditions for couplings and thread protection.
NOTE 2  Supplementary requirements that can optionally be agreed for enhanced leak resistance connections (LC) are given in A.9 SR22.
This document can also be applied to tubulars with connections not covered by ISO or API standards.
This document is applicable to products including the following grades of pipe: H40, J55, K55, N80, L80, C90, R95, T95, P110, C110 and Q125.
This document is not applicable to threading requirements.
NOTE 3  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.

This document specifies requirements for and gives guidance on the application of life cycle costing to create value for the development activities and operations associated with drilling, exploitation, processing and transport of petroleum, petrochemical and natural gas resources. This document covers facilities and associated activities within different business categories (upstream, midstream, downstream and petrochemical).
The life cycle costing process as described in this document is applicable when making decisions between competing options that are differentiated by cost and/or economic value. This document is not concerned with decision-making related to the economic performance of individual options or options differentiated by factors other than cost or economic value.
Guidance is provided on the management methodology and application of life cycle costing in support of decision-making across life cycle phases. The extent of planning and management depends on the magnitude of the costs involved, the potential value that can be created and the life cycle phase. It also provides the means of identifying cost drivers and provides a cost-control framework for these cost drivers, allowing effective cost control and optimization over the entire life of an asset.

This document illustrates the formulae and templates necessary to calculate the various pipe properties given in International Standards, including
—          pipe performance properties, such as axial strength, internal pressure resistance and collapse resistance,
—          minimum physical properties,
—          product assembly force (torque),
—          product test pressures,
—          critical product dimensions related to testing criteria,
—          critical dimensions of testing equipment, and
—          critical dimensions of test samples.
For formulae related to performance properties, extensive background information is also provided regarding their development and use.
Formulae presented here are intended for use with pipe manufactured in accordance with ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L, as applicable. These formulae and templates can be extended to other pipe with due caution. Pipe cold-worked during production is included in the scope of this document (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 document.
Application of performance property formulae in this document 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 is exercised when using the performance formulae for drill pipe.
This document and the formulae contained herein relate the input pipe manufacturing parameters in ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L to expected pipe performance. The design formulae in this document are not to be understood as a manufacturing warranty. Manufacturers are typically licensed to produce tubular products in accordance with manufacturing specifications which control the dimensions and physical properties of their product. Design formulae, 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 document is not a design code. It only provides formulae and templates for calculating the properties of tubulars intended for use in downhole applications. This document 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 formulae and listed values for performance properties in this document assume a benign environment and material properties conforming to ISO 11960 or API 5CT, ISO 11961 or API 5D and ISO 3183 or API 5L. Other environments can 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 document.
Throughout this document tensile stresses are positive.

This document specifies detailed manufacturing requirements for circular steel and nickel alloy compact flanged connections and associated seal rings, for designated pressures and temperatures in class designations CL 150 (PN 20) to CL 1500 (PN 260) for nominal sizes from DN 15 (NPS ½) to DN 1200 (NPS 48), and for CL 2500 (PN 420) for nominal sizes from DN 15 (NPS ½) to DN 600 (NPS 24).
NOTE     NPS is expressed in accordance with ASME B36.10M and ASME B36.19M.
This document is applicable to welding neck flanges, blind flanges, paddle spacers and spacer blinds (paddle blanks), valve/equipment integral flanges, orifice spacers, reducing threaded flanges and rigid interfaces for use in process piping for the petroleum, petrochemical and natural gas industries.
This document is applicable within a temperature range from −196 °C to +250 °C.
This document is not applicable for external pressure.

This document describes general principles and gives requirements and recommendations for the selection and qualification of metallic materials for service in equipment used in oil and gas production and in natural-gas sweetening plants in H2S-containing environments, where the failure of such equipment can pose a risk to the health and safety of the public and personnel or to the environment. It can be applied to help to avoid costly corrosion damage to the equipment itself. It supplements, but does not replace, the materials requirements given in the appropriate design codes, standards, or regulations.
This document addresses all mechanisms of cracking that can be caused by H2S, including sulfide stress cracking, stress corrosion cracking, hydrogen-induced cracking and stepwise cracking, stress-oriented hydrogen-induced cracking, soft zone cracking, and galvanically induced hydrogen stress cracking.
Table 1 provides a non-exhaustive list of equipment to which this document is applicable, including exclusions.
This document applies to the qualification and selection of materials for equipment designed and constructed using load controlled design methods. For design utilizing strain-based design methods, see Clause 5.
This document is not necessarily applicable to equipment used in refining or downstream processes and equipment.

This document specifies requirements and provides recommendations applicable to the following types of fixed steel offshore structures for the petroleum and natural gas industries:
?  caissons, free-standing and braced;
?  jackets;
?  monotowers;
?  towers.
In addition, it is applicable to compliant bottom founded structures, steel gravity structures, jack-ups, other bottom founded structures and other structures related to offshore structures (such as underwater oil storage tanks, bridges and connecting structures).
This document contains requirements for planning and engineering of the design, fabrication, transportation and installation of new structures as well as, if relevant, their future removal.
NOTE 1            Specific requirements for the design of fixed steel offshore structures in arctic environments are presented in ISO 19906.
NOTE 2            Requirements for topsides structures are presented in ISO 19901-3; for marine operations in, ISO 19901‑6; for structural integrity management, in ISO 19901-9 and for the site-specific assessment of jack-ups, in ISO 19905‑1.

This document gives requirements and recommendations for the selection and qualification of CRAs (corrosion-resistant alloys) and other alloys for service in equipment used in oil and natural gas production and natural gas treatment plants in H2S-containing environments whose failure can pose a risk to the health and safety of the public and personnel or to the environment. It can be applied to help avoid costly corrosion damage to the equipment itself. It supplements, but does not replace, the materials requirements of the appropriate design codes, standards, or regulations.
This document addresses the resistance of these materials to damage that can be caused by sulfide stress cracking (SSC), stress corrosion cracking (SCC), and galvanically induced hydrogen stress cracking (GHSC).
This document is concerned only with cracking. Loss of material by general (mass loss) or localized corrosion is not addressed.
Table 1 provides a non-exhaustive list of equipment to which this document is applicable, including exclusions.
This document applies to the qualification and selection of materials for equipment designed and constructed using load controlled design methods. For design utilizing strain-based design methods, see ISO 15156‑1:2020, Clause 5.
This document is not necessarily suitable for application to equipment used in refining or downstream processes and equipment.

This document gives requirements and recommendations for the selection and qualification of carbon and low-alloy steels for service in equipment used in oil and natural gas production and natural gas treatment plants in H2S-containing environments, whose failure can pose a risk to the health and safety of the public and personnel or to the environment. It can be applied to help to avoid costly corrosion damage to the equipment itself. It supplements, but does not replace, the materials requirements of the appropriate design codes, standards or regulations.
This document addresses the resistance of these steels to damage that can be caused by sulfide stress cracking (SSC) and the related phenomena of stress-oriented hydrogen-induced cracking (SOHIC) and soft-zone cracking (SZC).
This document also addresses the resistance of these steels to hydrogen-induced cracking (HIC) and its possible development into stepwise cracking (SWC).
This document is concerned only with cracking. Loss of material by general (mass loss) or localized corrosion is not addressed.
Table 1 provides a non-exhaustive list of equipment to which this document is applicable, including exclusions.
This document applies to the qualification and selection of materials for equipment designed and constructed using load controlled design methods. For design utilizing strain-based design methods, see ISO 15156-1:2020, Clause 5.
Annex A lists SSC-resistant carbon and low alloy steels, and A.2.4 includes requirements for the use of cast irons.
This document is not necessarily suitable for application to equipment used in refining or downstream processes and equipment.

This document establishes the principles, specifies the requirements and provides guidance for ice management (IM) in arctic and cold regions, from the point of view of planning, engineering, implementation and documentation. Reference to arctic and cold regions in this document is deemed to include both the Arctic and other regions characterized by low ambient temperatures, sea ice, icebergs and icing conditions. These regions are often remote and lacking in marine and communications infrastructure.
Ice management to support the following in-ice activities and infrastructures are covered by this document:
—          floating moored and/or dynamically positioned drilling vessels, coring vessels, production facilities and work-over vessels;
—          construction and installation (includes trenching, dredging, pipe laying);
—          tanker loading and other offloading operations;
—          protecting subsea structures and equipment;
—          seismic operations;
—          oil spill response;
—          bottom founded structures (fixed platforms and movable structures, including jack-ups).
This document also applies to mobilization, demobilization and construction support services, because these can be affected by ice conditions.
In view of the wide range of possible offshore operations in arctic and cold regions, this document provides guidelines, but does not present typical ice management plans for field operations.
This document does not provide requirements, recommendations or guidance pertaining to the design of structures, systems and components used in ice management, beyond the principles given. This document does not provide specific formulations for ice loads, which are covered by ISO 19906.
This document is not applicable to coastal port operations and to commercial trading vessels conducting transit or convoy operations.

This document specifies the minimum technical requirements for surface preparation, materials, application, inspection and testing of internal coating and lining systems that are intended to be applied on internal surfaces of process vessels that are subject to marked pressure/temperature changes and/or potentially corrosive conditions or processes and aggressive chemicals, used in the oil and gas industry.
This document covers both new construction and maintenance works of process vessels as well as the repair of defective and deteriorated coating and lining systems.
This document also provides the minimum requirements for the coated and lined samples and the criteria for their approval.

This document is applicable to pressure-relieving and vapour depressuring systems. Although intended for use primarily in oil refineries, it is also applicable to petrochemical facilities, gas plants, Liquefied Natural Gas (LNG) facilities and oil and gas production facilities. The information provided is designed to aid in the selection of the system that is most appropriate for the risks and circumstances involved in various installations.
This document supplements API Std 521, 6th edition (2014), the requirements of which are applicable with the exceptions specified in this document.

This document specifies the requirements for a series of compact steel gate, globe and check valves for petroleum and natural gas industry applications.
It is applicable to valves of:
—     nominal sizes DN 8, 10, 15, 20, 25, 32, 40, 50, 65, 80 and 100,
—     corresponding to nominal pipe sizes NPS ¼, ⅜, ½, , 1, 1¼, 1½, 2, 2½, 3 and 4,
—     pressure designations PN 16, 25, 40, 63, 100, 250 and 400, and
—     pressure designations Class 150, 300, 600, 800, 1 500 and 2 500.
Class 800 is not a listed class designation, but is an intermediate Class number widely used for socket welding and threaded end compact valves covered by this document. There is no equivalent PN designation.
This document includes provisions for the following valve characteristics:
—     outside screw with rising stems (OS & Y): in sizes 8 ≤ DN ≤ 100;
—     inside screw with rising stems (ISRS): in sizes 8 ≤ DN ≤ 65 with a pressure designation PN ≤ 100 or Class ≤ 800;
—     socket welding or threaded ends: in sizes 8 ≤ DN ≤ 65;
—     flanged or butt-welding ends excluding flanged end Class 800;
—     bonnet joint construction that is bolted, welded or threaded with seal weld;
—     bonnet joint construction that uses a union nut with a pressure designation PN ≤ 45 or Class ≤ 800;
—     body seat openings;
—     materials: as specified;
—     testing and inspection.
This document covers valve end flanges in accordance with EN 1092-1 and ASME B16.5 and valve body ends having tapered pipe threads in accordance with ISO 7-1 or ASME B1.20.1. It is applicable to extended body construction in sizes 15 ≤ DN ≤ 50 with pressure designations Class 800 and Class 1 500 and to bellows and bellows assembly construction adaptable to gate or globe valves in sizes 8 ≤ DN ≤ 50. Also covered are requirements for bellows stem seal type testing.

This document specifies general safety requirements for the design, testing and production of manually operated elevators. The requirements are applicable for on- and off-shore applications of such elevators in the petroleum and petrochemical industries.
This document deals with significant hazards, hazardous situations and events, as listed in Annex A, relevant to elevators when used as intended and under the conditions of misuse foreseeable by the manufacturer.
This document does not cover any other type of elevator. It is not applicable to the following types of products:
-   lifting nubbins;
-   lifting plugs;
-   lifting subs;
-   internal gripping devices;
-   equipment for lifting tubular from and onto a vessel;
-   elevator links or bails.
This document is not applicable to manually operated elevators manufactured before the date of this publication.

This document specifies the technical delivery conditions for corrosion-resistant alloy seamless tubular products for casing, tubing, coupling stock and accessory material (including coupling stock and accessory material from bar) for two product specification levels:
—     PSL-1, which is the basis of this document;
—     PSL-2, which provides additional requirements for a product that is intended to be both corrosion and cracking resistant for the environments and qualification method specified in Annex G and in the ISO 15156 series.
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 document are special alloys in accordance with ISO 4948-1 and ISO 4948-2.
NOTE 2  For the purpose of this document, NACE MR0175 is equivalent to the ISO 15156 series.
NOTE 3  Accessory products can be manufactured from coupling stock and tubular material, or from solid bar stock or from bored and heat heat-treated bar stock as covered in Annex F.
This document contains no provisions relating to the connection of individual lengths of pipe.
This document contains provisions relating to marking of tubing and casing after threading.
This document is applicable to the following five groups of products:
a)   group 1, which is composed of stainless alloys with a martensitic or martensitic/ferritic structure;
b)   group 2, which is composed of stainless alloys with a ferritic-austenitic structure, such as duplex and super-duplex stainless alloy;
c)   group 3, which is composed of stainless alloys with an austenitic structure (iron base);
d)   group 4, which is composed of nickel-based alloys with an austenitic structure (nickel base);
e)   group 5, which is composed of bar only (Annex F) in age-hardened (AH) nickel-based alloys with austenitic structure.
NOTE 4  Not all PSL-1 categories and grades can be made cracking resistant in accordance with the ISO 15156 series and are, therefore, not included in PSL-2.

This document defines quality management system requirements for product and service supply organizations to the petroleum, petrochemical and natural gas industries.
This document is written as a supplement to ISO 9001:2015. The supplementary requirements and guidance to ISO 9001:2015 have been developed to manage supply chain risks and opportunities associated with the petroleum, petrochemical and natural gas industries and to provide a framework for aligning requirements with complementary standards employed within the industries.

This document specifies general safety requirements for the design, testing and production of powered elevators. The requirements are applicable for onshore and offshore applications of such elevators in the petroleum and petrochemical industries.
This document does not cover any other type of elevator. It is not applicable to the following types of products:
—     remote control devices;
—     lifting nubbins;
—     lifting plugs;
—     lifting subs;
—     internal gripping devices;
—     equipment for lifting tubular from and onto a vessel;
—     elevator links or bails.
This list is not exhaustive.
This document is not applicable to powered elevators manufactured before the date of this publication.
NOTE    Annex A provides the relation between the clauses of the European Directive on machinery (Directive 2006/42/EC) and this document, for potential significant hazards and the safety requirements dealing with them for powered elevators.

This document provides procedures for testing well cements and cement blends for use in the petroleum and natural gas industries in a deepwater environment, or areas with a low seafloor temperature, or areas where low well temperatures exist.
This document supplements API RP 10B-3, 2nd edition (2016), the requirements of which are applicable with the exceptions specified in this document.
This document excludes the mitigation of shallow water flow in deepwater wells.
NOTE       This is addressed in API RP 65.

ISO 35106:2017 specifies requirements and provides recommendations and guidance for the collection, analysis and presentation of relevant physical environmental data for activities of the petroleum and natural gas industries in arctic and cold regions. Activities include design and operations, which involve planning and actual execution.
Reference to arctic and cold regions in this document is deemed to include both the Arctic and other locations characterized by low ambient temperatures and the presence or possibility of sea ice, icebergs, shelf ice, glaciers, icing conditions, persistent snow cover, frozen surfaces of lakes and rivers, localized and rapidly changing weather systems and/or permafrost.
ISO 35106:2017 outlines requirements for a range of different operations that have been or are presently being undertaken and for existing design concepts. This document can also be used for other operations and new design concepts in arctic and cold regions as long as it is recognized that all data requirements are not necessarily addressed.

This document specifies requirements and provides recommendations applicable to fixed, floating and grounded concrete offshore structures for the petroleum and natural gas industries and for structures supporting nationally-important power generation, transmission or distribution facility. This document specifically addresses
—     the design, construction, transportation and installation of new structures, including requirements for in-service inspection and possible removal of structures,
—     the assessment of structures in service, and
—     the assessment of structures for reuse at other locations.
This document is intended to cover the engineering processes needed for the major engineering disciplines to establish a facility for offshore operation.

ISO 35101:2017 describes the working environment that can be expected when operating oil and gas facilities in Arctic environments/climate. ISO 35101:2017 provides principles and generic guidelines for the design and operation of fixed and floating oil and gas facilities both onshore and offshore.
The aim of ISO 35101:2017 is to ensure optimal health, safety, human performance and decision-making conditions for people working on oil and gas facilities in Arctic conditions.
ISO 35101:2017 applies to the design and operation of new facilities and structures, and to modification of existing facilities for operation in the Arctic environment. This also includes offshore and onshore exploration and accommodation units for such activities.
ISO 35101:2017 is divided into three main parts.
-      The first part (Clause 5) describes the general principles and guidelines for risk management.
-      The second part (Clause 6) describes the general working environment (working environment hazards found in many workplaces and provides some threshold limit values (TLVs) and design references that can be especially challenging in Arctic conditions.
-      The third part (Clause 7 to Clause 9) addresses the climatic conditions expected in the Arctic. Clause 8 describes working environment design and technical solutions, while Clause 9 describes working environment operational requirements for prevention and management of cold-related problems.

ISO 18647:2017 gives requirements for the design, fabrication, installation, commissioning and integrity management of modular drilling rigs on offshore fixed platforms.
The modular drilling rig includes some or all of the equipment as follows:
-      drilling equipment including a derrick/mast and its controls that can be moved by skidding a drilling support structure;
-      drilling support equipment which includes support facilities such as power supply/distribution system;
-      mud and cement storage, mixing, monitoring and control equipment.
ISO 18647:2017 is applicable to the modular drilling equipment on offshore structures for the petroleum and natural gas industries, as follows:
-      new equipment arranged in a modularized form;
-      the equipment contained in several modules, each of which can be lifted and installed on to the platform, however, the equipment may be arranged within the modules as is convenient;
-      the modules assembled together offshore for hook up and commissioning;
-      intended for long term use on a new fixed offshore structure;
-      Intended for temporary use on a number of different offshore platforms.
ISO 18647:2017 is not applicable to drilling equipment
-      installed on mobile offshore units, and
-      intended primarily for onshore use.
ISO 18647:2017 does not apply to those parts and functions of an offshore platform that are not directly related to drilling.

ISO 35103:2017 gives requirements, specifications and guidelines to ensure that environmental monitoring in the offshore Arctic region is fit for purpose. The Arctic region includes the territory lying to the North of the Arctic Circle (Latitude 66°33′45.8″). This document can be applied to sub-Arctic locations which experience Arctic-like conditions and contain relevant components of a cold-climate ecosystem.
ISO 35103:2017 is applicable to all Arctic oil and gas operations from licence block acquisition through exploration, engineering design, construction, commissioning, operation, decommissioning and restoration. It covers the offshore or maritime environment, including for the purposes of this document, the fully marine and estuarine waters of the Arctic, whether frozen or ice-free. The environment includes all relevant physical, chemical and biological components. Monitoring methods for onshore (terrestrial) environments are not covered in this document, although onshore environments are included where monitoring is required at onshore locations in relation to an offshore development.
ISO 35103:2017 covers both monitoring of environmental aspects for normal, abnormal and emergency conditions, and monitoring of environmental impacts. It includes monitoring in near-field, far-field, transboundary and regional scales, but does not include global environmental monitoring.

This document specifies requirements and gives recommendations on the management of geohazard risks during the pipeline design, construction and operational periods.
This document is applicable to all operators and pipelines (existing and proposed/under construction).
This document applies to onshore gathering and transmission pipelines used in the petroleum and natural gas industries.
NOTE       This document is not applicable to piping and pipelines within well-defined plants and facilities, such as pump or compressor stations, processing facilities or refineries. It is assumed that the facility site as a whole will be subject to a separate geohazard assessment to evaluate applicable natural and man-made hazards. Nevertheless, this document can provide useful guidance for assessing the geohazard threat to facilities, including the pipelines within the facility.
This document is applicable to all reasonable and credible natural hazards induced by natural forces and hazards induced by human activity that manifest similarly to natural hazards collectively referred to as "geological hazards" or "geohazards", or through industry as attributed to "natural forces". Geohazards covered by this document include, but are not limited to (not given in order of significance):
—          mass wasting processes, including landslides, lateral spreads, rockfalls, debris flows, avalanches, and similar processes whether naturally occurring or anthropogenic;
—          land subsidence and/or sinkhole formation, whether naturally occurring such as from dissolution of salt or carbonate rock formations (karst formation) or human caused, such as from underground mining or withdrawal of subsurface fluids such as groundwater and oil and gas;
—          seismic hazards, such as ground shaking, fault rupture, liquefaction, flow failures and lateral spreading or associated secondary effects, such as seismically triggered landslides;
—          volcanic hazards, such as lahars, pyroclastic flows, lava flows, dam break, and volcanically induced seismicity (excluding ashfall), where such hazards can be reasonably predicted;
—          hydrologic processes, such as flooding, vertical scour of river bottoms, channel migration and bank erosion, channel avulsion, rapid lake drainage;
—          permafrost/periglacial processes and geothermal effects, such as thermal degradation, frost heave or thaw settlement, thermal erosion, thermokarst;
—          surface (overland), trench backfill, or earthwork fill erosion;
—          expansion or collapsing processes caused by expansive and collapsible soils, such as glaciomarine clays, collapsible loess, etc.
This document is not applicable to atmospheric/environmental effects, such as the following:
—          high winds induced from hurricanes and tornadoes and similar storms, except where such events are reasonably predictable and will induce geohazards such as landslides, erosion, etc.;
—          lightning;
—          forest or brush fires;
—          ashfall from volcanic eruptions.
Furthermore, this document is not applicable to cascading events, where one remote event leads to a chain of events that eventually induces a geohazard near the pipeline. It is only applicable to geohazards that directly affect the pipeline or RoW.

This document specifies principles for the structural integrity management (SIM) of offshore structures subjected to known or foreseeable types of actions.
This document specifies requirements and provides recommendations applicable to the following types of fixed steel offshore structures for the petroleum and natural gas industries:
—          caissons, free-standing and braced;
—          jackets;
—          monotowers;
—          towers.
This document is applicable to topsides, including but not limited to the main decks, deck legs, topsides modules, crane pedestals, helideck, drilling derrick, skid beams, flare booms, exhaust towers, radio tower, conductor support frames, and lifeboat davits. In addition, it is applicable to compliant bottom founded structures, steel gravity structures, jack-ups, other bottom founded structures and other structures related to offshore structures (e.g. underwater oil storage tanks, bridges and connecting structures), to the extent to which its requirements are relevant.
This document contains requirements for planning and engineering of the following tasks:
a)    integrity management data requirements;
b)    in-service inspection and integrity management of both new and existing structures;
c)    assessment of existing structures;
d)    evaluation of structures for reuse at different locations;
e)    evaluation of structures for their future removal.

This document specifies tests to perform in order to determine the galling tendency, sealing performance and structural integrity of casing and tubing connections. "Casing" and "tubing" apply to the service application and not to the diameter of the pipe.
This document covers the testing of connections for the most commonly encountered well conditions. Not all possible service scenarios are included. For example, the presence of a corrosive fluid, which can influence the service performance of a connection, is not considered.
This document supplements API RP 5C5:2017, the requirements of which are applicable with the exceptions specified in this document.

This document specifies requirements and provides recommendations and guidance for the design, construction, transportation, installation and decommissioning of offshore structures related to the activities of the petroleum and natural gas industries in arctic and cold regions. Reference to arctic and cold regions in this document is deemed to include both the Arctic and other locations characterized by low ambient temperatures and the presence or possibility of sea ice, icebergs, icing conditions, persistent snow cover, and/or permafrost.
The objective of this document is to ensure that complete structures, including substructures, topsides structures, floating production vessel hulls, foundations and mooring systems, in arctic and cold regions provide an appropriate level of reliability with respect to personnel safety, environmental protection and asset value. Value includes value to the owner, to the industry and to society in general.
This document does not contain requirements for the operation, maintenance, service-life inspection or repair of arctic and cold region offshore structures, unless the design strategy imposes specific requirements such as ice management (IM) to reduce ice actions.
Provisions for the operation, maintenance, service‐life inspection and repair of mobile units are given in ISO 19905-1 and ISO 19905-3, supplemented by the provisions relating to ice actions and IM in this document.
This document 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. This document applies to equipment used for the positioning and disconnection of floating structures (see Clause 13).

This document specifies general requirements and recommendations for the design and assessment of bottom-founded (fixed) and buoyant (floating) offshore structures.
This document is applicable for all phases of the life of the structure, including:
—         successive stages of construction (i.e. fabrication, transportation, and installation),
—         service in-place, both during design life and during any life extensions, and
—         decommissioning, and removal.
This document contains general requirements and recommendations for both the design of new build structures and for the structural integrity management and assessment of existing structures.
This document does not apply to subsea and riser systems or pipeline systems.

This document provides requirements and guidance for the structural design and/or assessment of floating offshore platforms used by the petroleum and natural gas industries to support the following functions:
—          production;
—          storage and/or offloading;
—          drilling and production;
—          production, storage and offloading;
—          drilling, production, storage and offloading.
NOTE 1    Floating offshore platforms are often referred to using a variety of abbreviations, e.g. FPS, FSU, FPSO (see Clauses 3 and 4), in accordance with their intended mission.
NOTE 2    In this document, 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 document, the term "production" includes "early production".
This document is not applicable to the structural systems of mobile offshore units (MOUs). These include, among others, the following:
—          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.
This document is 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 re‑use at different locations.
The following types of floating structure are explicitly considered within the context of this document:
a)   ship-shaped structures and barges;
b)   semi-submersibles;
c)   spars;
d)   shallow-draught cylindrical structures.
In addition to the structural types listed above, this document covers other floating platforms intended to perform the above functions, consisting of partially submerged buoyant hulls made up of any combination of plated and space frame components. These other structures can have a great range of variability in geometry and structural forms (e.g. tension leg platforms) and, therefore, can be only partly covered by the requirements of this document. In other cases, specific requirements stated in this document can be found not to apply to all or part of a structure under consideration.
NOTE 4    Requirements for topsides structures are presented in ISO 19901-3.
In the above cases, conformity with this document requires the design to be based upon its underpinning principles and to achieve a level of safety equivalent, or superior, to the level implicit in it.
NOTE 5    The speed of evolution of offshore technology often far exceeds the pace at which the industry achieves substantial agreement on innovation in structural concepts, structur

This document provides objectives, functional requirements and guidelines for techniques for the analysis and design of surface process safety systems for offshore installations used for the recovery of hydrocarbon resources.
It also provides recommendations and requirements on support systems which complement the process safety systems in reducing risk.
NOTE       These are not intended to be exhaustive.
The scope of this document is limited to specifying the methods by which the asset is protected against loss of containment of hydrocarbon or other hazardous materials.
This document is applicable to
a)    fixed offshore structures, and
b)    floating offshore production installations
for the petroleum and natural gas industries.
This document is not applicable to mobile offshore units and subsea installations.
NOTE        Nevertheless, many of the principles contained in this document can be used as guidance.

This document specifies requirements and gives recommendations on the management of integrity of a pipeline system throughout its life cycle, which includes design, construction, commissioning, operation, maintenance and abandonment.
This document is applicable to offshore pipelines for transporting petroleum and natural gas. It is applicable to rigid steel pipelines. It is not applicable to flexible pipelines, dynamic risers or those constructed from other materials, such as glass-reinforced plastics.
NOTE 1    An offshore pipeline system extends to:
—   the first valve, flange or connection above water on platform or subsea mechanical connector with subsea structure (i.e. manifold or dynamic riser);
—   the connection point to the offshore installation (i.e. piping manifolds are not included);
—   the first valve, flange, connection or isolation joint at a landfall, unless otherwise specified by the onshore legislation.
NOTE 2    The components mentioned above (valve, flange, connection, isolation joint) include also any pup pieces, i.e. the offshore pipeline system extends to the weld beyond the pup piece, see Figure 1.
This document is used for integrity management, which is initiated at the design and construction stage of the pipeline. Where requirements of a design and construction standard (e.g. ISO 13623) are different, the provisions of this document will enhance the design and construction from an integrity perspective.

ISO/TS 35105:2018 provides recommendations for material selection, manufacturing and fabrication requirements, testing and qualification of steel structures and components for offshore and onshore petroleum and natural gas facilities operating in Arctic and cold environments.
ISO/TS 35105:2018 is intended to be used as a supplement to existing standards for steel structures where the particular operating conditions in Arctic regions are not sufficiently addressed.
ISO/TS 35105:2018 gives particular requirements to ensure safe operation with respect to the risk of brittle fracture at low temperatures. These requirements will affect the selection of material grade and design class as well as the technical delivery conditions for steel. They will also affect the fabrication requirements as well as testing and qualification requirements.
ISO/TS 35105:2018 also gives recommendations:
-      to mitigate the operational and integrity aspects related to snow and ice accretion on topside structures;
-      to take into account the particular Arctic operating conditions in corrosion assessments and requirements for corrosion protection systems;
-      for particular operational requirements to ensure safe operation in Arctic regions.
The requirements in this document are applicable to any operating temperatures, but particular requirements related to de-rating (loss of strength) at high temperatures are not addressed. Limitations to the applicable minimum design temperature caused by the capability of the materials' low temperature performance can exist, but are not a limitation for the scope of this document.
As a practical guideline for the use of this document, low temperature is defined as lowest anticipated service temperature (LAST) below ?10 °C.
NOTE       For determination of LAST, see 6.3.2.

This document specifies requirements and gives recommendations for the mechanical design, material selection, fabrication, inspection, testing and preparation for shipment of shell-and-tube heat exchangers for the petroleum, petrochemical and natural gas industries.
This document supplements API Std 660, 9th edition (2015), the requirements of which are applicable with the exceptions specified in this document.
This document is applicable to the following types of shell-and-tube heat exchangers: heaters, condensers, coolers and reboilers.
This document is not applicable to vacuum-operated steam surface condensers and feed-water heaters.

This document describes various corrosion under insulation (CUI) environments in refineries and other related industries and environments, and establishes CUI environmental categories including operating temperature ranges from −45 °C to 204 °C for topside and aboveground service only. This document specifies both established and other test methods for the assessment of coatings used for prevention of CUI for each given environment. This document also provides acceptance criteria for each CUI environment.
NOTE       The test results and acceptance criteria can be considered an aid in the selection of suitable coating systems. For service or peak temperatures below −45 °C an optional cryogenic test can be incorporated and for over 204 °C testing acceptance criteria can be agreed between interested parties. Additional or other test and acceptance measures are possible, but require particular agreement between the interested parties.
This document covers spray-applied coatings applied on new carbon and austenitic stainless steel for use in CUI service. This document does not cover testing of sacrificial coatings, such as inorganic zinc, as these coatings can be consumed quickly in wet environments. Developing accelerated corrosion testing for what can be continuous wet service with sacrificial coatings is beyond the scope of this document.
"Non-through porosity" thermal spray aluminium coatings with greater than 250 µm dry film thickness can be tested and qualified in accordance with this document. This document does not cover tape and sheet applied products for use in preventing CUI.
This document does not deal with other aspects of coating degradation, such as those caused by abrasion, erosion, ultraviolet degradation or other methods that can exist given specific environment and construction methods.

This document specifies the technical delivery conditions for steel drill-pipes with upset pipe-body ends and weld-on tool joints for use in drilling and production operations in petroleum and natural gas industries for three product specification levels (PSL-1, PSL-2 and PSL-3). The requirements for PSL-1 form the basis of this document. The requirements that define different levels of standard technical requirements for PSL-2 and PSL-3 are in Annex G.
This document covers the following grades of drill-pipe:
—          grade E drill-pipe;
—          high-strength grades of drill-pipe, grades X, G and S;
—          enhanced H2S resistance drill pipe, grades D and F.
A typical drill-pipe configuration is given, showing main elements and lengths (see Figure B.1). The main dimensions and masses of the grades of drill-pipe are given in both SI units (see Table A.1) and in USC units (see Table C.1).
This document can also be used for drill-pipe with tool joints not specified by ISO or API standards.
By agreement between purchaser and manufacturer, this document can also be applied to other drill-pipe body and/or tool-joint dimensions. This document lists supplementary requirements that can optionally be agreed between purchaser and manufacturer, for testing, performance verification and non-destructive examination (see Annex E).
This document does not consider performance properties, nor performance degradation of the product when in service.
NOTE 1    In this document, drill-pipe is designated by label 1, label 2, grade of material (E, X, G, S, D and F), upset type and type of rotary shouldered connection. Designations are used for the purpose of identification in ordering.
NOTE 2    Reference can be made to ISO 10424-2 or API Spec 7-2 for the detailed requirements for the threading of drill-pipe tool joints.
NOTE 3    Reference can be made to API RP 7G for the performance properties of the drill-pipe.

This document establishes a procedure for verifying that the manufacturer of special materials for the petroleum, petrochemical and natural gas industries has sufficient competence and experience of the relevant material grades of metal, and the necessary facilities and equipment, to manufacture these materials in the required shapes and sizes with acceptable properties according to the applicable standard, material specification and/or material data sheet specified by the purchaser.
This document is applicable to manufacturers of various materials, product forms and manufacturing processes when specified by the purchaser. This document has been established considering especially, but not exclusively:
a)    duplex stainless steel;
b)    high alloyed austenitic stainless steel;
c)    nickel-based alloys;
d)    titanium and its alloys.
This document is also applicable to the processes of induction bending and strain-hardened products.