This document specifies methods for the calibration of tanks above eight metres in diameter with cylindrical courses that are vertical. It provides two methods for determining the volumetric quantity of the liquid contained within a tank at gauged liquid levels.
NOTE For optical-reference-line method, the optical (offset) measurements required to determine the circumferences can be taken internally or externally, provided that insulation is removed if tank is insulated.
The methods are suitable for tilted tanks with up to 3 % deviation from the vertical provided that a correction is applied for the measurement tilt, as described in ISO 7507-1.
These methods are alternatives to other methods such as strapping (ISO 7507-1) and the optical-triangulation method (ISO 7507-3).

  • Standard
    33 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Standard
    28 pages
    English language
    sale 15% off
  • Standard
    30 pages
    French language
    sale 15% off
  • Draft
    28 pages
    English language
    sale 15% off
  • Draft
    30 pages
    French language
    sale 15% off

This document establishes all necessary steps to properly measure and account for the quantities of cargoes on liquefied natural gas (LNG) carriers. This includes, but is not limited to, the measurement of liquid volume, vapour volume, temperature and pressure, and accounting for the total quantity of the cargo on board. This document describes the use of common measurement systems on board LNG carriers, the aim of which is to improve the general knowledge and processes in the measurement of LNG for all parties concerned. This document provides general requirements for those involved in the LNG trade on ships and onshore.

  • Standard
    64 pages
    English language
    sale 15% off
  • Draft
    62 pages
    English language
    sale 15% off

This document gives requirements and guidance on the selection, accuracy, installation, commissioning, calibration and verification of automatic tank thermometers (ATTs) in fiscal/custody transfer applications. The ATT is used for measuring the temperature of petroleum and liquid petroleum products having a Reid vapour pressure less than 100 kPa, stored in atmospheric storage tanks. This document is not applicable to the measurement of temperature in caverns or in refrigerated storage tanks.

  • Standard
    15 pages
    English language
    sale 15% off

This document specifies requirements for weldable structural steels made of hot finished seamless and high frequency welded hollow sections to be used in the fabrication of fixed offshore structures.
The following thickness limitations are given in this standard:
-   for seamless hollow sections up to and including 65 mm;
-   for HFW hollow sections up to and including 25,4 mm.
Greater thicknesses can be agreed, provided the technical requirements of this European Standard are maintained.
This European Standard is applicable to steels for offshore structures, designed to operate in the offshore sector but not to steels supplied for the fabrication of subsea pipelines, risers, process equipment, process piping and other utilities. It is primarily applicable to the North Sea Sector, but may also be applicable in other areas provided that due consideration is given to local conditions e.g. design temperature.
NOTE   This document has an informative Annex E on the prequalification of steels for fixed offshore structures in arctic areas.
Minimum yield strengths up to 770 MPa are specified together with impact properties at temperatures down to -40 °C.

  • Standard
    62 pages
    English language
    sale 10% off
    e-Library read for
    1 day

This document gives requirements and guidance on the accuracy, installation, commissioning, calibration and verification of automatic level gauges (ALGs). It applies to ALGs which are both intrusive and non-intrusive types, in fiscal/custody transfer applications for measuring the level of petroleum and petroleum products having a Reid vapour pressure less than 100 kPa, stored in atmospheric storage tanks. This document is not applicable to the measurement of level in refrigerated storage tanks with ALG equipment.

  • Standard
    19 pages
    English language
    sale 15% off

This document specifies the requirements for a heavy-duty series of bolted bonnet steel gate valves for petroleum refinery and related applications where corrosion, erosion and other service conditions can indicate a need for full port openings, heavy wall sections and large stem diameters.
This document sets forth the requirements for the following gate valve features:
— bolted bonnet;
— outside screw and yoke;
— rising stems;
— non-rising handwheels;
— single or double gate;
— wedge or parallel seating;
— metallic seating surfaces;
— flanged or butt-welding ends.
It covers valves of the nominal sizes DN:
— 25; 32; 40; 50; 65; 80; 100; 150; 200; 250; 300; 350; 400; 450; 500; 600;
corresponding to nominal pipe sizes NPS:
— 1; 1¼; 1½; 2; 2½; 3; 4; 6; 8; 10; 12; 14; 16; 18; 20; 24;
applies for pressure Class designations:
— 150; 300; 600; 900; 1 500; 2 500;
and applies for pressure PN designations:
— 16, 25, 40, 63, 100, 160, 250 and 400.

  • Standard
    44 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Standard
    38 pages
    English language
    sale 15% off
  • Standard
    38 pages
    French language
    sale 15% off
  • Standard
    38 pages
    French language
    sale 15% off
  • Draft
    38 pages
    English language
    sale 15% off

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.

  • Standard
    63 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    62 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    31 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    28 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    45 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    43 pages
    English language
    sale 10% off
    e-Library read for
    1 day

This document provides descriptions of the different types of pipe provers, otherwise known as displacement provers, currently in use. These include sphere (ball) provers and piston provers operating in unidirectional and bidirectional forms. It applies to provers operated in conventional, reduced volume, and small volume modes.
This document gives guidelines for:
—    the design of pipe provers of each type;
—    the calibration methods;
—    the installation and use of pipe provers of each type;
—    the interaction between pipe provers and different types of flowmeters;
—    the calculations used to derive the volumes of liquid measured (see Annex A);
—    the expected acceptance criteria for fiscal and custody transfer applications, given as guidance for both the calibration of pipe provers and when proving flowmeters (see Annex C).
This document is applicable to the use of pipe provers for crude oils and light hydrocarbon products which are liquid at ambient conditions. The principles apply across applications for a wider range of liquids, including water. The principles also apply for low vapour pressure, chilled and cryogenic products, however use with these products can require additional guidance.

  • Standard
    118 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    111 pages
    English language
    sale 10% off
    e-Library read for
    1 day

This document provides a common approach and guidance to those undertaking assessment of the major safety hazards as part of the planning, design, and operation of LNG facilities onshore and at shoreline using risk-based methods and standards, to enable a safe design and operation of LNG facilities. The environmental risks associated with an LNG release are not addressed in this document. This document is applicable both to export and import terminals but can be applicable to other facilities such as satellite and peak shaving plants. This document is applicable to all facilities inside the perimeter of the terminal and all hazardous materials including LNG and associated products: LPG, pressurized natural gas, odorizers, and other flammable or hazardous products handled within the terminal. The navigation risks and LNG tanker intrinsic operation risks are recognised, but they are not in the scope of this document. Hazards arising from interfaces between port and facility and ship are addressed and requirements are normally given by port authorities. It is assumed that LNG carriers are designed according to the IGC code, and that LNG fuelled vessels receiving bunker fuel are designed according to IGF code. Border between port operation and LNG facility is when the ship/shore link (SSL) is established. This document is not intended to specify acceptable levels of risk; however, examples of tolerable levels of risk are referenced. See IEC 31010 and ISO 17776 with regard to general risk assessment methods, while this document focuses on the specific needs scenarios and practices within the LNG industry.

  • Technical specification
    58 pages
    English language
    sale 15% off
  • Draft
    58 pages
    English language
    sale 15% off
  • Draft
    58 pages
    English language
    sale 15% off

This document provides descriptions of the different types of pipe provers, otherwise known as displacement provers, currently in use. These include sphere (ball) provers and piston provers operating in unidirectional and bidirectional forms. It applies to provers operated in conventional, reduced volume, and small volume modes.
This document gives guidelines for:
—    the design of pipe provers of each type;
—    the calibration methods;
—    the installation and use of pipe provers of each type;
—    the interaction between pipe provers and different types of flowmeters;
—    the calculations used to derive the volumes of liquid measured (see Annex A);
—    the expected acceptance criteria for fiscal and custody transfer applications, given as guidance for both the calibration of pipe provers and when proving flowmeters (see Annex C).
This document is applicable to the use of pipe provers for crude oils and light hydrocarbon products which are liquid at ambient conditions. The principles apply across applications for a wider range of liquids, including water. The principles also apply for low vapour pressure, chilled and cryogenic products, however use with these products can require additional guidance.

  • Standard
    118 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    111 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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).

  • Standard
    57 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    59 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    9 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    7 pages
    English language
    sale 10% off
    e-Library read for
    1 day

This document describes three procedures (A, B and C) covering determinations of flash no-flash and flash point.
Rapid equilibrium procedures A and B are applicable to flash no-flash and flash point tests of paints, including water-borne paints, varnishes, binders for paints and varnishes, adhesives, solvents, petroleum products including aviation turbine, diesel and kerosene fuels, fatty acid methyl esters and related products over the temperature range –30 °C to 300 °C. The rapid equilibrium procedures are used to determine whether a product will or will not flash at a specified temperature (flash no-flash procedure A) or the flash point of a sample (procedure B). When used in conjunction with the flash detector (A.1.6), this document is also suitable to determine the flash point of fatty acid methyl esters (FAME). The validity of the precision is given in Table 2.
Non-equilibrium procedure C is applicable to petroleum products including aviation turbine, diesel and kerosine fuels, and related petroleum products, over the temperature range –20 °C to 300 °C. The non-equilibrium procedure is automated to determine the flash point. Precision has been determined over the range 40 °C to 135 °C.
For specifications and regulations, procedures A or B are routinely used (see 10.1.1).

  • Standard
    35 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    33 pages
    English language
    sale 10% off
    e-Library read for
    1 day

This document provides descriptions of the different types of pipe provers, otherwise known as displacement provers, currently in use. These include sphere (ball) provers and piston provers operating in unidirectional and bidirectional forms. It applies to provers operated in conventional, reduced volume, and small volume modes. This document gives guidelines for: — the design of pipe provers of each type; — the calibration methods; — the installation and use of pipe provers of each type; — the interaction between pipe provers and different types of flowmeters; — the calculations used to derive the volumes of liquid measured (see Annex A); — the expected acceptance criteria for fiscal and custody transfer applications, given as guidance for both the calibration of pipe provers and when proving flowmeters (see Annex C). This document is applicable to the use of pipe provers for crude oils and light hydrocarbon products which are liquid at ambient conditions. The principles apply across applications for a wider range of liquids, including water. The principles also apply for low vapour pressure, chilled and cryogenic products, however use with these products can require additional guidance.

  • Standard
    109 pages
    English language
    sale 15% off
  • Standard
    118 pages
    French language
    sale 15% off

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.

  • Standard
    9 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    7 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    2 pages
    English language
    sale 15% off
  • Standard
    2 pages
    French language
    sale 15% off

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.

  • Standard
    55 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    52 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    12 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    7 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    55 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    52 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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).

  • Standard
    90 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    87 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    46 pages
    English language
    sale 15% off
  • Standard
    49 pages
    French language
    sale 15% off
  • Standard
    49 pages
    French language
    sale 15% off

This document specifies the methodology to determine if a laboratory is in control in the execution of a standard test method. By using statistical control charts and following this document the 'in-statistical-control' status is established and validated. In-statistical-control means the test results produced by the lab on control samples are reasonably consistent with expectation over time; with random variation scattered around a stable expected centre due to common causes only
This document explicitly defines ‘site precision’ conditions as  single apparatus, multi-operators, over a long time horizon. It specifies control charts that are most appropriate for ISO TC28 test methods where the dominant common cause variation is associated with the long term, multiple operator conditions as described by "site precision" conditions. The control charts specified for determination of in-statistical-control are: Individual (I), Moving Range of 2 (MR2), Exponentially Weighted Moving Average (EWMA), and zone-based run rules (commonly known as Western Electric (WE)run rules.
The procedures in this document have been designed specifically for petroleum and petroleum related products, which are normally considered as homogeneous and for test methods which show normality in obtaining their results. However, the procedures described in this document can also be applied to other types of homogeneous products and test methods.

  • Standard
    44 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    37 pages
    English language
    sale 10% off
    e-Library read for
    1 day

This document is written in preparation of future standardization and provides guidance on the
impact of the injection of H2 into the gas infrastructure from the input of gas into the on­shore
transmission network up to the inlet connection of gas appliances. 
Furthermore, it identifies the expected revision need of the existing CEN/TC 243 standards as
well as the need of further new standardisation deliverables. 
It examines the effects on each part of the gas infrastructure in the scope of the CEN/TC 234
Working Groups 1 to 12 inclusive, based on available studies, reports and research. Due to
several limitations at different hydrogen concentrations, the impacts are specified. 
For some specific impact, pre­standardization research is needed. 
By convention, for this technical report, the injection of pure hydrogen, i. e. without trace
components is considered. 
The information from this report is intended to define the CEN/TC 234 work program for the
coverage of H2NG in relation to the scope of the CEN/TC 234 and its WGs. 
NOTE Progress on hydrogen will develop over time. In principle this will be reflected in the
standardisation process in CEN/TC 234.

  • Technical report
    127 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    128 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    63 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    62 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    31 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    28 pages
    English language
    sale 10% off
    e-Library read for
    1 day

This document gives requirements for the design, setting depth and installation of conductors used by the offshore petroleum and natural gas industries. This document covers:
-   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/cementing, and jetting;
-   installation requirements for the installation methods, i.e. selection principles, operating procedures and parameters.
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 appropriate intervals through the water column to support the conductor withstand metocean 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 caisson in cantilever mode installed in shallow water, typically 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 seafloor.
This document does not apply to drilling risers.

  • Standard
    45 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    43 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    116 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    113 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    76 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    74 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    13 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    9 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    55 pages
    English language
    sale 15% off
  • Standard
    59 pages
    French language
    sale 15% off

This document specifies the requirements for design including shape and dimensions, material as well as strength for pipe support from NPS 2 up to NPS 36 except for U-bolt and U-strap. This document covers topside systems for fixed or floating offshore oil and gas projects. This document applies for design temperature of support within the range between –23 °C up to 200 °C. This document is limited to metallic pipes only.
This document covers such requirements for following pipe supports:
—   clamped shoe;
—   welded shoe;
—   U-bolt;
—   U-strap;
—   bracing for branch connection;
—   trunnion and stanchion;
—   guide support(guide, hold-down, guide/hold-down).
This document addresses design requirements of the listed items above, hence the document does not necessarily cover all other types of pipe supports.

  • Standard
    57 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    59 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    36 pages
    English language
    sale 15% off
  • Standard
    42 pages
    French language
    sale 15% off

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.

  • Standard
    23 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    14 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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).

  • Standard
    49 pages
    English language
    sale 15% off
  • Standard
    51 pages
    French language
    sale 15% off

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.

  • Standard
    12 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    7 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    75 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    63 pages
    English language
    sale 10% off
    e-Library read for
    1 day

This document is written in preparation of future standardization and provides guidance on the
impact of the injection of H2 into the gas infrastructure from the input of gas into the on­shore
transmission network up to the inlet connection of gas appliances. 
Furthermore, it identifies the expected revision need of the existing CEN/TC 243 standards as
well as the need of further new standardisation deliverables. 
It examines the effects on each part of the gas infrastructure in the scope of the CEN/TC 234
Working Groups 1 to 12 inclusive, based on available studies, reports and research. Due to
several limitations at different hydrogen concentrations, the impacts are specified. 
For some specific impact, pre­standardization research is needed. 
By convention, for this technical report, the injection of pure hydrogen, i. e. without trace
components is considered. 
The information from this report is intended to define the CEN/TC 234 work program for the
coverage of H2NG in relation to the scope of the CEN/TC 234 and its WGs. 
NOTE Progress on hydrogen will develop over time. In principle this will be reflected in the
standardisation process in CEN/TC 234.

  • Technical report
    127 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    128 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    4 pages
    English language
    sale 15% off
  • Standard
    5 pages
    French language
    sale 15% off
  • Standard
    5 pages
    French language
    sale 15% off
  • Draft
    4 pages
    English language
    sale 15% off

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.

  • Technical specification
    163 pages
    English language
    sale 15% off

This document specifies methods for the calibration of tanks above eight metres in diameter with cylindrical courses that are vertical. It provides two methods for determining the volumetric quantity of the liquid contained within a tank at gauged liquid levels. NOTE For optical-reference-line method, the optical (offset) measurements required to determine the circumferences can be taken internally or externally, provided that insulation is removed if tank is insulated. The methods are suitable for tilted tanks with up to 3 % deviation from the vertical provided that a correction is applied for the measurement tilt, as described in ISO 7507-1. These methods are alternatives to other methods such as strapping (ISO 7507-1) and the optical-triangulation method (ISO 7507-3).

  • Standard
    33 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Standard
    28 pages
    English language
    sale 15% off
  • Standard
    30 pages
    French language
    sale 15% off
  • Draft
    28 pages
    English language
    sale 15% off
  • Draft
    30 pages
    French language
    sale 15% off

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, marine surface waves, electrical resistivity imaging and electromagnetic imaging.

  • Standard
    90 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    87 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Technical specification
    25 pages
    English language
    sale 15% off
  • Draft
    25 pages
    English language
    sale 15% off

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.

  • Standard
    116 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    113 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Standard
    1 page
    English language
    sale 15% off
  • Standard
    1 page
    French language
    sale 15% off
  • Draft
    1 page
    English language
    sale 15% off
  • Draft
    1 page
    French language
    sale 15% off

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.

  • Standard
    13 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    9 pages
    English language
    sale 10% off
    e-Library read for
    1 day

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.

  • Standard
    76 pages
    English language
    sale 10% off
    e-Library read for
    1 day
  • Draft
    74 pages
    English language
    sale 10% off
    e-Library read for
    1 day