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

This document provides the methods for the testing of well cement formulations to determine the dimension changes during the curing process (cement hydration) at atmospheric and elevated pressure and the stress generated by expansion in a confined environment under elevated temperature and pressure.

This document provides general principles, requirements and recommendations for the assessment of stability of fibre-reinforced composite materials for service in equipment used in oil and gas production environments.
This document describes the procedures for comparative testing of composite materials consisting of polymers (thermoplastics and thermosets) and re-enforcing materials e.g. glass, carbon, aramid and metals as continuous fibres or woven fabric used in equipment for oil and gas production.
Testing and characterization of neat resins and fibre products are beyond the scope of this document.
The equipment considered includes, but is not limited to, non-metallic pipelines, piping, liners and downhole tool components.
Blistering by rapid gas decompression, coatings and compounded particulate- and short fibre-reinforced composites are excluded from the scope of this document.

This document specifies testing, performance, and marking requirements for casing bow-spring centralizers to be used in oil and natural gas well construction. The procedures give guidance on verification testing for the manufacturer’s design, materials, and process specifications, and periodic testing to confirm the consistency of product performance. This specification is not applicable to other devices, such as rigid centralizers and cement baskets, or bow-spring centralizers used for other purposes (e.g., wireline tools, gravel pack, inner string).
This document is a supplement to API Spec 10D 7th edition (2021), the requirements of which are applicable with the exceptions specified in this document.

This document specifies objectives, functional requirements and guidelines for emergency response (ER) measures on installations used for the development of offshore hydrocarbon resources. It is applicable to:
—     fixed offshore structures;
—     floating systems for production, storage and off-loading.
NOTE          For mobile offshore units, the ER plans developed in conformance with the requirements and recommendations of the International Maritime Organization (IMO) are generally adequate for the normal, independent operation of the unit in most locations. The following aspects of ER planning are not generally addressed by IMO and are topics intended for inclusion in the scope of this document where relevant to the specific installation:
—      area evacuation, e.g. precautionary evacuation in areas of tropical revolving storms;
—      combined operations (where an integrated command and ER system is relevant);
—      arctic operations;
—      uncontrolled flow from a well.

This document specifies requirements for surface preparation, materials, application, inspection and testing of internal coating lining systems that are intended to be applied on internal surfaces of steel storage tanks of crude oil, hydrocarbons and water for corrosion protection.
It covers both new construction and maintenance works of tank internal coating and lining as well as the repair of defective and deteriorated coating/lining.
This document also provides requirements for shop performance testing of the coated/lined samples and the criteria for their approval.

This document specifies the objectives and functional requirements for the control and mitigation of fires and explosions on offshore installations used for the development of hydrocarbon resources in oil and gas industries. The object is to achieve:
safety of personnel;
protection of the environment;
protection of assets;
minimization of financial and consequential losses of fires and explosions.
This document is applicable to the following:
fixed offshore structures;
floating systems for production, storage, and offloading.
Mobile offshore units and subsea installations are excluded, although many of the principles contained in this document can be used as guidance.

This document provides requirements, guidance and information for the design and fabrication of topsides structure for offshore structures, including in-service, pre-service and post-service conditions.
The actions on topsides structure and the action effects in structural components are derived from this document, where necessary in combination with other International Standards in the ISO 19901 series (e.g. ISO 19901-1 for wind actions - see 7.6.2, ISO 19901-2 for seismic actions - see 7.7) and ISO 19902 for fatigue design (see 6.7).
This document is applicable to the following:
—     topsides of fixed offshore structures;
—     discrete structural units placed on the hull structures of floating offshore structures and mobile offshore units;
—     topsides of arctic offshore structures, excluding winterization (see ISO 19906).
If any part of the topsides structure forms part of the primary structure of the overall structural system which resists global platform actions, the requirements of this document are supplemented with applicable requirements in ISO 19902, ISO 19903, ISO 19904-1, ISO 19905-1, ISO 19905-3 and ISO 19906.
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 document.
This document also addresses prevention, control and assessment of fire, explosions and other accidental events.
The fire and explosion provisions of this document can be applied to those parts of the hulls of floating structures and mobile offshore units that contain hydrocarbon processing, piping or storage.
NOTE          Requirements for structural integrity management are presented in ISO 19901-9.
This document applies to structural components including the following:
—     primary and secondary structure in decks, module support frames and modules;
—     flare structures;
—     crane pedestal and other crane support arrangements;
—     helicopter landing decks (helidecks);
—     permanent bridges between separate offshore structures;
—     masts, towers and booms on offshore structures.
This document provides requirements for selecting and using a national building standard with a correspondence factor for determining the resistance of rolled and welded non-circular prismatic components and their connections.

This document specifies requirements and provides recommendation and guidance for the elevated site-specific assessment (SSA-E) of independent leg jack‑up units for use in the petroleum and natural gas industries. It addresses:
a)       occupied non-evacuated, occupied evacuated and unoccupied jack‑ups;
b)       the installed (or elevated) phase at a specific site.
It also addresses the requirement that the as-installed condition matches the assumptions used in the assessment.
This document does not address the site-specific assessment of installation and removal (SSA-I).
To ensure acceptable reliability, the provisions of this document form an integrated approach, which is used in its entirety for the site-specific assessment of a jack‑up.
When assessing a jack-up operating in regions subject to sea ice and icebergs, it is intended that the assessor supplements the provisions of this document with the relevant provisions relating to ice actions contained in ISO 19906 and procedures for ice management contained in ISO 35104. This document does not address design, transit to and from site, or installation and removal from site.
This document is applicable only to independent leg mobile jack-up units that are structurally sound and adequately maintained, which is normally demonstrated through holding a valid recognized classification society, classification certificate. Jack‑ups that do not hold a valid recognized classification society certificate are assessed according to the provisions of ISO 19902, supplemented by methodologies from this document, where applicable.
NOTE 1        Well conductors can be a safety-critical element for jack‑up operations. However, the integrity of well conductors is not part of the site-specific assessment process for jack‑ups and is, therefore, not addressed in this document. See A.1 for guidance on this topic.
NOTE 2        RCS rules and the IMO MODU code (International Maritime Organisation Mobile Offshore Drilling Unit code) provide guidance for the design of jack-ups.

ISO 25457:2008 specifies requirements and provides guidance for the selection, design, specification, operation and maintenance of flares and related combustion and mechanical components used in pressure relieving and vapour-depressurizing systems for petroleum, petrochemical and natural gas industries.
Although ISO 25457:2008 is primarily intended for new flares and related equipment, it can also be used in the evaluation of existing flare facilities.
Further guidance and best practices are provided for the selection, specification and mechanical details for flares and on the design, operation and maintenance of flare combustion and related equipment.
ISO 25457:2008 also includes a set of data sheets, together with instructions and guidelines, for use in communicating and recording design information.

This document provides a set of unified requirements and specifications regarding material quality level and pre-qualification for piping material of seamless pipes, welded pipes, wrought fittings, plates, forgings, bars, castings and piping bolts/nuts used for piping systems in the oil and gas industry, both offshore and onshore.
This document covers the following material grades:
-   C-Mn steel;
-   high strength steel;
-   austenitic stainless steels;
-   duplex stainless steels;
-   nickel alloy;
-   Cu-Ni alloy;
-   titanium alloy;
-   Cu-alloy.

This document specifies requirements for project specific product and process qualification of field
applied wet thermal insulation systems applied at interfaces (e.g. field joints) and pre-fabricated
insulation in the petroleum and natural gas industries.
This document is applicable to wet thermal insulation systems submerged in seawater.
This document is not applicable to:
— the project qualification of anticorrosion coatings or the requirements for application thereof;
— thermal insulation in the annulus of a steel pipe-in-pipe system.

This document specifies requirements for the validation of wet thermal insulation systems applied to
pipelines and subsea equipment in the oil and gas industry.
This document is applicable to wet thermal insulation systems submerged in seawater.
This document is not applicable to:
— maintenance works on existing installed wet thermal insulation systems;
— qualification for anti-corrosion coating;
— thermal insulation in the annulus of a steel pipe-in-pipe system.

This document specifies requirements for project specific product and process qualification of wet
thermal insulation systems applied to pipelines in a factory setting and subsea equipment in the oil and
gas industries.
This document is not applicable to:
— pre-fabricated insulation;
— thermal insulation in the annulus of a steel pipe-in-pipe system;
— maintenance works on existing installed wet thermal insulation systems;
— project qualification of anticorrosion coatings or the requirements for application thereof.

This document specifies requirements for the design, design verification and validation, manufacturing and data control, performance ratings, functional evaluations, handling and storage of tubing-deployed electrical submersible pump (ESP) systems. Additionally, this document provides requirements for assembled ESP system.
This document is applicable to those ESP related components meeting the definition of centrifugal pumps, including gas handling devices, discharge heads, seal chamber sections, intake systems, mechanical gas separators, asynchronous 3 phase - 2 pole induction motors (herein motor), shaft couplings, downhole power cables (herein power cables), motor lead extension, and pothead. Components supplied under the requirements of this document exclude previously used subcomponents, except where the use of such subcomponents is as defined in this document (Clause 9).
This document addresses design validation performance rating requirements by component (see Annex A), requirements for determining ratings as an assembled system (see Annex B), functional evaluation: single component (see Annex C) and cable reference information (see Annex D).
This document addresses functional evaluation guidelines for assembled ESP systems, establishing recommended operating range (ROR) of the ESP system (see Annex F), example user/purchaser ESP functional specification form (see Annex G), considerations for the use of 3-phase low and medium voltage adjustable speed drives for ESP applications (see Annex H), analysis after ESP use (see Annex I), downhole monitoring of ESP assembly operation (see Annex J), information on permanent magnet motors for ESP applications (see Annex K) and users guide (see Annex L).
This document also includes a user guide that offers a high-level process workflow when applying this document.
This document does not apply to: wireline and coiled tubing-deployed ESP systems, motor shrouds and pump shrouds, electric penetrators and feed-through systems, cable clamps and banding, centralizers, intake screens, passive gas separators, by-pass tools, check and bleeder valves, component adaptors, capillary lines, electric surface control equipment, downhole permanent magnet motors and non-conventionally configured ESP systems such as inverted systems. This document does not apply to Repair and redress equipment requirements.

This document specifies requirements and provides recommendations and guidelines for marine soil investigations regarding:
a)    objectives, planning and execution of marine soil investigations;
b)    deployment of investigation equipment;
c)    drilling and logging;
d)    in situ testing;
e)    sampling;
f)     laboratory testing;
g)    reporting.
Although this document focuses on investigations of soil, it also provides guidance, with less detail, for investigations of chalk, calcareous soils, cemented soils and weak rock.
Foundation design is not covered by this document.
NOTE 1    ISO 19901‑4 and the respective design standards covering foundation design for the specific types of offshore structures to meet the requirements of application specific standards are given on the ISO website.
The results from marine geophysical investigations are, when available and where appropriate, used for planning, optimization and interpretation of marine soil investigations.
This document neither covers the planning, execution and interpretation of marine geophysical investigations nor the planning and scope of geohazard assessment studies, only the corresponding marine soil investigations aspects thereof.
NOTE 2    ISO 19901-10 covers the planning, execution and interpretation of marine geophysical investigations.
This document specifies requirements and provides guidance for obtaining measured values and derived values. This document excludes requirements for determination of design values and representative values. Limited guidance is provided in 11.3 related to data interpretation.
This document is intended for clients, soil investigation contractors, designers, installation contractors, geotechnical laboratories and public and regulatory authorities concerned with marine soil investigations for any type of offshore structures, or geohazard assessment studies.

This document specifies the technical delivery conditions for bends made by the induction bending process for use in pipeline transportation systems for the petroleum and natural gas industries as defined in ISO 13623.
NOTE 1   ISO 13623 is modified adopted as EN 14161 to exclude on-land supply systems used by the European gas supply industry from the input of gas into the on-land transmission network up to the inlet connection of gas appliances.
This document is applicable to induction bends made from seamless and welded pipe of unalloyed or low-alloy steels.
NOTE 2   These are typically C-Mn steels or low-alloy steels that are appropriate for the corresponding level and grade of line pipe in accordance with ISO 3183.
This document specifies the requirements for the manufacture of two product specification levels (PSLs) of induction bends corresponding to product specification levels given for pipe in ISO 3183:2012.
This document is not applicable to the selection of the induction bend PSL. It is the responsibility of the purchaser to specify the PSL, based upon the intended use and design requirements; see also ISO 3183, Introduction.
This document is not applicable to pipeline bends made by other manufacturing processes.
On-land supply systems used by the European gas supply industry from the input of gas into the on-land transmission network up to the inlet connection of gas appliances are excluded from the scope of this document.

This document specifies the technical delivery conditions for bends made by the cold bending process for bend with radii 5xOD or higher for use in pipeline transportation systems for the petroleum and natural gas industries as defined in ISO 13623. Short radius factory cold bends should not be used for pipeline.
NOTE 1   ISO 13623 is modified adopted as EN 14161 to exclude on-land supply systems used by the European gas supply industry from the input of gas into the on-land transmission network up to the inlet connection of gas appliances.
This document also specifies the requirements for the manufacture of two product specification levels (PSLs) of cold bends corresponding to product specification levels given for pipe in ISO 3183. This document is applicable to cold bends made from seamless and welded pipe of unalloyed or low-alloy steels.
NOTE 2   These are typically C-Mn steels or low-alloy steels that are appropriate for the corresponding level and grade of line pipe in accordance with ISO 3183.
This document is not applicable to the selection of the cold bend product specification level. It is the responsibility of the purchaser to specify the PSL, based upon the intended use and design requirements.
NOTE 3   See also ISO 3183:2012, Introduction.
This document is not applicable to field cold bends and pipeline bends made by other manufacturing processes.
On-land supply systems used by the European gas supply industry from the input of gas into the on-land transmission network up to the inlet connection of gas appliances are excluded from the scope of this document.

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 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 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 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 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 defines requirements for the fabrication, welding, examination and testing of new, metallic piping systems up to 69 000 kPa (ga) maximum, within temperature range limits for the materials meeting the requirements of ASME B31.3, on fixed and floating offshore production facilities and onshore production, processing and liquefaction plants.
This document is applicable to all pressure retaining components and any non-pressure retaining component, such as a pipe support, welded directly to a pressure retaining component.
This document is not applicable to:
- marine-related piping systems, e.g. ballasting piping systems, systems covered by classification societies;
- non-metallic piping systems.

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 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 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 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 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 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 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 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 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 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.