ISO/TC 67 - Materials, equipment and offshore structures for petroleum, petrochemical and natural gas industries

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 specifies the technical requirements for carbon steel and low-alloy steel forged flanges for use in pipeline transportation systems for the petroleum and natural gas industries as defined in ISO 13623. This document applies to weldneck and blind flanges (full face, raised face, and RTJ groove) as well as anchor, swivel-ring flanges and orifice flanges. This document designates those categories of flanges that meet the industry's need to match ISO 3183 pipe. These flanges are for normal and low-temperature service and include supplementary requirements where required for sour service. Materials for, or the attachment of, factory-welded extensions, bolting materials, gaskets, slip-on flanges or flanged fittings are not covered by this document. This document is not applicable to integrally cast or forged flanges for valves, pumps or other equipment. This document does not cover the selection of the flange category or pressure class. Sizes and pressure classes listed in ISO 7005-1 and applicable to this document are as follows: — DN 10 (NPS 1/2) to DN 1500 (NPS 60); — PN 20 (class 150), PN 50 (class 300), PN 100 (class 600), PN 150 (class 900), PN 250 (class 1500), PN 420 (class 2500).

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 provides procedures for assessment of casing connections for those field applications in which the operating temperatures cyclically vary between minimum values appreciably below 180 °C and maximum values that range from 180 °C to 350 °C or above, and in which the primary axial loading on the casing-connection system is strain-based and driven by constrained thermal expansion and leads to a stress state that exceeds the casing-connection system's yield envelope. NOTE This document can be considered complementary to ISO 13679 (and its core content per API Specification 5C5), which applies to classic elastic-design applications. This document contains an evaluation procedure for a candidate connection comprising of uniquely defined pin, box and interfacial components. The evaluation procedure includes: — Material property tests to assess relevant properties of the candidate connection pin and box components; — Analytical tasks to determine configuration of connection samples for physical tests, which are chosen based on worst-case combinations of the connection geometry and material properties; — Full-scale testing tasks to measure the candidate connection galling resistance, structural integrity and sealability under loading representative of connection assembly and thermal well service. This document does not address impacts of external pressure, incomplete lateral pipe support, rotational fatigue, formation-induced shear, or environmentally-induced corrosion or cracking. Clause 6 describes fundamental assumptions adopted in this document.

This document specifies requirements for ceramic lined tubing (CLT) used in the petroleum and natural gas industries, including configuration and materials, manufacturing, inspection and testing, marking, packaging, transportation, and storage. This document is applicable to CLT manufactured by centrifugal self-propagating high-temperature synthesis. The applicable outside diameter of CLT ranges from 42,16 mm (1,66 inch) to 114,3 mm (4-1/2 inch). The steel grades include H40, J55, and N80 type 1. NOTE Applicability of this document to other sizes and higher steel grades can be by agreement between the manufacturer and the purchaser. CLT is suitable for extracting multiphase fluid, hydrocarbon gas, hydrocarbon liquid, and water under corrosive, abrasive, wax deposition, scaling, and high temperature environments.

This document gives guidance on the risk-based approach to follow for the design and operation of the LNG bunker transfer system, including the interface between the LNG bunkering supply facilities and receiving LNG fuelled vessels. This document provides requirements and recommendations for the development of a bunkering site and facility and the LNG bunker transfer system, providing the minimum functional requirements qualified by a structured risk assessment approach taking into consideration LNG properties and behaviour, simultaneous operations and all parties involved in the operation. This document is applicable to bunkering of both seagoing and inland trading vessels. It covers LNG bunkering from shore or ship, mobile to ship and ship to ship LNG supply scenarios, as described in Clause 4.

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 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 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 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 technical delivery conditions for unalloyed or low-alloy steel seamless and welded pipeline fittings for use in pipeline transportation systems for the petroleum and natural gas industries as defined in ISO 13623. This document is applicable to welding-end fittings such as elbows, caps, tees, single or multiple extruded headers, reducers, and transition sections made from seamless and welded pipe of unalloyed or low-alloy steels. This document specifies two classes of fitting one related to material used in non-sour service and one for material to be use in sour service environment as shown in Table 1. This document is not applicable to the selection of the fitting class. This document is not applicable to the materials for, or the attachment of, factory-welded extensions.

This document provides specific requirements and guidance for the design and operation of floating LNG storage and regasification units (FSRU) described in ISO 20257-1. This document is applicable to offshore, near-shore or docked FSRUs and to both new-built and converted FSRUs. This document includes requirements to the jetty when an FSRU is moored to a jetty.

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 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 establishes the general principles for the evaluation and minimization of the effects of stray current corrosion on external surfaces of buried or immersed pipeline systems caused by AC and DC electrical interference. Other stray current effects such as overheating, and interference with welding operations are not covered in this document. A brief description of AC effects, general principles and some guidelines, are provided. NOTE 1 See ISO 18086 for the effects of alternating current on buried or immersed pipelines. Systems that can also be affected by stray currents include buried or immersed metal structures such as the following: a) pipeline systems; b) metal sheathed cables; c) tanks and vessels; d) earthing systems; e) steel reinforcement in concrete; f) sheet steel piling. This document gives guidelines for — the design of cathodic protection systems that might produce stray currents, — the design of pipeline systems, or elements of pipeline systems, which are buried or immersed, and which can be subject to stray current corrosion, and — the selection of appropriate protection or mitigation measures. Internal corrosion risks from stray currents are not dealt with in detail in this document but principles and measures described here can be applicable for minimizing the interference effects. NOTE 2 The impact of electromagnetic interference on above-ground appurtenances of pipeline systems is covered in EN 50443, IEC 61140, IEC 60364-4-41, IEC 60479-1, IEC 60364-5-52, IEC/TS 61201 and IEC/TR 60479-5. This document can also be used for pipeline systems outside of the petrochemical and natural gas industries and other buried or immersed structures. NOTE 3 EN 50162 provides guidance for railway related structures.

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 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 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 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 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 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 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 provides requirements and guidance for the design and operation of floating liquefied natural gas (LNG) installations, including installations for the liquefaction, storage, vaporisation, transfer and handling of LNG, in order to have a safe and environmentally acceptable design and operation of floating LNG installations. This document is applicable to: — floating LNG liquefaction installations (plant) — FLNG; — floating LNG regasification installations (plant) — FSRU; — floating storage units — FSU. This document is applicable to offshore, near-shore or docked floating LNG installations. This document includes any jetty in the scope in case of docked floating LNG installations with regards to the mooring. This document briefly describes floating LNG mooring concepts. This document is applicable to both newbuilt and converted floating LNG installations, and addresses specific requirements. This document is not applicable to: — onshore LNG storage, liquefaction and/or regasification installations/plants, except for docked FSRU and/or FLNG installations; — offshore LNG plants based on non-floating structure (such as gravity based structure [GBS] principle); and — support onshore based facilities (such as support vessels, tugs, etc.). This document is not intended for design floating power generation facilities though relevant parts of this document can be used. This document is not intended to cover LNG as fuel bunkering applications.

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 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 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 describes a method for determining the resistance of Cryogenic Spill Protection (CSP) systems to vapour generated from a cryogenic liquid release where the liquid content is practically zero. It is applicable where CSP systems are installed on carbon steel. The test provided in this document is not applicable to high pressure cryogenic liquid releases that can be found in refrigeration circuits and in LNG streams immediately post-liquefaction.

This document specifies requirements for the manufacture of two product specification levels (PSL 1 and PSL 2) of seamless and welded steel pipes for use in pipeline transportation systems in the petroleum and natural gas industries. This document supplements API Spec 5L, 46th edition (2018), the requirements of which are applicable with the exceptions specified in this document. This document is not applicable to cast pipe.

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. 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 1 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 2 See also ISO 3183:2012, Introduction. This document is not applicable to field cold bends and pipeline bends made by other manufacturing processes.

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.

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.

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 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 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 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 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.

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, structural shapes or forms, structural components and associated analysis and design practices, which are continuously refined and enhanced. On the other hand, International Standards can only capture explicit industry consensus, which requires maturation and acceptance of new ideas. Consequently, advanced structural concepts can, in some cases, only be partly covered by the requirements of this document. This document is applicable to steel floating structures. The principles documented herein are, however, considered to be generally applicable to structures fabricated in materials other

1.1 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. 1.2 This document is applicable to onshore pipeline systems used in transportation in the petroleum and natural gas industries, connecting wells, production plants, process plants, refineries and storage facilities, including any section of a pipeline constructed within the boundaries of such facilities for connection purposes. The extent of pipeline systems covered by this document is illustrated in Figure 1. This document does not deal specifically with the integrity of non-pipe elements. The pipeline segment between the wellsite and the gathering station, treatment plant or process plant (between Facilities 1 and 2 in Figure 1) is included in this document, though many mandatory elements of this document are not practical due to characteristics such as diameter, operating parameters, etc. 1.3 This document applies to rigid, steel pipelines. It is not applicable for flexible pipelines or those constructed from other materials, such as glass-reinforced plastics. 1.4 This document does not cover all conditions nor engineers' competency which might be related to pipeline integrity. The user can evaluate whether additional requirements are necessary. 1.5 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.

This document specifies the criteria and requirements for the in-field application of coatings, coating repair and coating rehabilitation on buried pipelines. This document specifies: — coating assessment (new and existing); — removal of degraded coatings; — surface preparation; — on site or in situ application of external coatings. It is applicable to petroleum or natural gas pipelines, with or without a cathodic protection system. The pipelines could be operational during the removal, preparation and application process. This document states qualification/testing for field contractors and site applied coatings to all of the pipeline components, including bends, tees, fittings, valves and interfaces between different coatings in soil-to-air pipeline sections. Technical and performance characteristics of the repair and rehabilitation coating materials are referenced to ISO 21809-3. The coating of field joints is outside the scope of this document. Field joint coatings are dealt with in ISO 21809-3. This document excludes the application of coatings when the pipeline is immersed (submerged).

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 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 describes a method for determining the resistance of a cryogenic spill protection (CSP) system to a cryogenic jet as a result of a pressurized release which does not result in immersion conditions. It is applicable where CSP systems are installed on carbon steel and will be in contact with cryogenic fluids. A cryogenic jet can be formed upon release from process equipment operating at pressure (e.g. some liquefaction processes utilize 40 to 60 bar operating pressure). Due to high pressure discharge, the cryogenic spillage protection can be compromised by the large momentum combined with extreme cryogenic temperature. Although the test uses liquid nitrogen as the cryogenic liquid, the test described in this document is representative of a release of LNG, through a 20 mm orifice or less, at a release pressure of 6 barg or less, based upon simulated parameters 1 m from the release point. Confidence in this test being representative is based upon a comparison of the expected dynamic pressure of the simulated release in comparison with dynamic pressure from releases in accordance with this document. It is not practical in this test to cover the whole range of cryogenic process conditions found in real plant conditions; in particular the test does not cover high pressure cryogenic jet releases that might be found in refrigeration circuits and in LNG streams immediately post-liquefaction. Liquid nitrogen is used as the cryogenic medium due to the ability to safely handle the material at the pressures described in this document. The test condition is run at nominally 8 barg pressure. ISO 20088-1 covers cryogenic release scenarios which can lead to pooling conditions for steel work protected by cryogenic spill protection as a result of a jet release or low pressure release of LNG or liquid nitrogen. ISO 20088-2 covers vapour phase exposure conditions as a result of a jet release or low pressure release of LNG or liquid nitrogen.