75.180.10 - Exploratory, drilling and extraction equipment
ICS 75.180.10 Details
Exploratory, drilling and extraction equipment
Erkundungstechnik. Abbautechnik
Matériel d'exploitation, de forage et d'extraction
Oprema za raziskovanje, vrtanje in odkopavanje
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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.
- Standard62 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard63 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft62 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard31 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft28 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard45 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft43 pagesEnglish languagesale 10% offe-Library read for1 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).
- Standard57 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft59 pagesEnglish languagesale 10% offe-Library read for1 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).
- Standard35 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft33 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard12 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft7 pagesEnglish languagesale 10% offe-Library read for1 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).
- Standard90 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft87 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard63 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft62 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard31 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft28 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard45 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft43 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard116 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft113 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard76 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft74 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard55 pagesEnglish languagesale 15% off
- Standard59 pagesFrench languagesale 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.
- Standard57 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft59 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard36 pagesEnglish languagesale 15% off
- Standard42 pagesFrench languagesale 15% off
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).
- Standard49 pagesEnglish languagesale 15% off
- Standard51 pagesFrench languagesale 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.
- Standard12 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft7 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard75 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft63 pagesEnglish languagesale 10% offe-Library read for1 day
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 specification163 pagesEnglish languagesale 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.
- Standard4 pagesEnglish languagesale 15% off
- Standard5 pagesFrench languagesale 15% off
- Standard5 pagesFrench languagesale 15% off
- Draft4 pagesEnglish languagesale 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.
- Standard90 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft87 pagesEnglish languagesale 10% offe-Library read for1 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 specification25 pagesEnglish languagesale 15% off
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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.
- Standard116 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft113 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard76 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft74 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard65 pagesEnglish languagesale 15% off
- Standard71 pagesFrench languagesale 15% off
- Standard71 pagesFrench languagesale 15% off
- Draft64 pagesEnglish languagesale 15% off
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.
- Standard281 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft231 pagesEnglish languagesale 10% offe-Library read for1 day
This document specifies the selection criteria and minimum requirements for protective coating systems for field maintenance and repair of risers exposed to conditions in the splash zone.
This document does not cover the selection of techniques and materials used to restore integrity of the risers to be coated.
This document neither covers the selection of additional mechanical protective materials that are not part of the described coating systems included in this document.
- Standard75 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft63 pagesEnglish languagesale 10% offe-Library read for1 day
This document illustrates the formulae and templates necessary to calculate the various pipe properties given in International Standards, including
— pipe performance properties, such as axial strength, internal pressure resistance and collapse resistance,
— minimum physical properties,
— product assembly force (torque),
— product test pressures,
— critical product dimensions related to testing criteria,
— critical dimensions of testing equipment, and
— critical dimensions of test samples.
For formulae related to performance properties, extensive background information is also provided regarding their development and use.
Formulae presented here are intended for use with pipe manufactured in accordance with ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L, as applicable. These formulae and templates can be extended to other pipe with due caution. Pipe cold-worked during production is included in the scope of this document (e.g. cold rotary straightened pipe). Pipe modified by cold working after production, such as expandable tubulars and coiled tubing, is beyond the scope of this document.
Application of performance property formulae in this document to line pipe and other pipe is restricted to their use as casing/tubing in a well or laboratory test, and requires due caution to match the heat-treat process, straightening process, yield strength, etc., with the closest appropriate casing/tubing product. Similar caution is exercised when using the performance formulae for drill pipe.
This document and the formulae contained herein relate the input pipe manufacturing parameters in ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L to expected pipe performance. The design formulae in this document are not to be understood as a manufacturing warranty. Manufacturers are typically licensed to produce tubular products in accordance with manufacturing specifications which control the dimensions and physical properties of their product. Design formulae, on the other hand, are a reference point for users to characterize tubular performance and begin their own well design or research of pipe input properties.
This document is not a design code. It only provides formulae and templates for calculating the properties of tubulars intended for use in downhole applications. This document does not provide any guidance about loads that can be encountered by tubulars or about safety margins needed for acceptable design. Users are responsible for defining appropriate design loads and selecting adequate safety factors to develop safe and efficient designs. The design loads and safety factors will likely be selected based on historical practice, local regulatory requirements, and specific well conditions.
All formulae and listed values for performance properties in this document assume a benign environment and material properties conforming to ISO 11960 or API 5CT, ISO 11961 or API 5D and ISO 3183 or API 5L. Other environments can require additional analyses, such as that outlined in Annex D.
Pipe performance properties under dynamic loads and pipe connection sealing resistance are excluded from the scope of this document.
Throughout this document tensile stresses are positive.
- Technical report239 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft236 pagesEnglish languagesale 10% offe-Library read for1 day
This document illustrates the formulae and templates necessary to calculate the various pipe properties given in International Standards, including
— pipe performance properties, such as axial strength, internal pressure resistance and collapse resistance,
— minimum physical properties,
— product assembly force (torque),
— product test pressures,
— critical product dimensions related to testing criteria,
— critical dimensions of testing equipment, and
— critical dimensions of test samples.
For formulae related to performance properties, extensive background information is also provided regarding their development and use.
Formulae presented here are intended for use with pipe manufactured in accordance with ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L, as applicable. These formulae and templates can be extended to other pipe with due caution. Pipe cold-worked during production is included in the scope of this document (e.g. cold rotary straightened pipe). Pipe modified by cold working after production, such as expandable tubulars and coiled tubing, is beyond the scope of this document.
Application of performance property formulae in this document to line pipe and other pipe is restricted to their use as casing/tubing in a well or laboratory test, and requires due caution to match the heat-treat process, straightening process, yield strength, etc., with the closest appropriate casing/tubing product. Similar caution is exercised when using the performance formulae for drill pipe.
This document and the formulae contained herein relate the input pipe manufacturing parameters in ISO 11960 or API 5CT, ISO 11961 or API 5D, and ISO 3183 or API 5L to expected pipe performance. The design formulae in this document are not to be understood as a manufacturing warranty. Manufacturers are typically licensed to produce tubular products in accordance with manufacturing specifications which control the dimensions and physical properties of their product. Design formulae, on the other hand, are a reference point for users to characterize tubular performance and begin their own well design or research of pipe input properties.
This document is not a design code. It only provides formulae and templates for calculating the properties of tubulars intended for use in downhole applications. This document does not provide any guidance about loads that can be encountered by tubulars or about safety margins needed for acceptable design. Users are responsible for defining appropriate design loads and selecting adequate safety factors to develop safe and efficient designs. The design loads and safety factors will likely be selected based on historical practice, local regulatory requirements, and specific well conditions.
All formulae and listed values for performance properties in this document assume a benign environment and material properties conforming to ISO 11960 or API 5CT, ISO 11961 or API 5D and ISO 3183 or API 5L. Other environments can require additional analyses, such as that outlined in Annex D.
Pipe performance properties under dynamic loads and pipe connection sealing resistance are excluded from the scope of this document.
Throughout this document tensile stresses are positive.
- Technical report239 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft236 pagesEnglish languagesale 10% offe-Library read for1 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.
- Standard65 pagesEnglish languagesale 15% off
- Standard67 pagesFrench languagesale 15% off
- Standard67 pagesFrench languagesale 15% off
- Draft64 pagesEnglish languagesale 15% off
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.
- Standard585 pagesEnglish languagesale 10% offe-Library read for1 day
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.
- Standard281 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft231 pagesEnglish languagesale 10% offe-Library read for1 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).
- Standard81 pagesEnglish languagesale 15% off
- Draft79 pagesEnglish languagesale 15% off
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.
- Standard22 pagesEnglish languagesale 15% off
- Standard25 pagesFrench languagesale 15% off
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- Draft24 pagesFrench languagesale 15% off
This document specifies general safety requirements for the design, testing and production of manually operated elevators. The requirements are applicable for on- and off-shore applications of such elevators in the petroleum and petrochemical industries.
This document deals with significant hazards, hazardous situations and events, as listed in Annex A, relevant to elevators when used as intended and under the conditions of misuse foreseeable by the manufacturer.
This document does not cover any other type of elevator. It is not applicable to the following types of products:
- lifting nubbins;
- lifting plugs;
- lifting subs;
- internal gripping devices;
- equipment for lifting tubular from and onto a vessel;
- elevator links or bails.
This document is not applicable to manually operated elevators manufactured before the date of this publication.
- Standard33 pagesEnglish languagesale 10% offe-Library read for1 day
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.
- Standard136 pagesEnglish languagesale 10% offe-Library read for1 day
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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.
- Standard19 pagesEnglish languagesale 10% offe-Library read for1 day
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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.
- Standard56 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft53 pagesEnglish languagesale 10% offe-Library read for1 day
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.
- Standard585 pagesEnglish languagesale 10% offe-Library read for1 day
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.
- Standard80 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft77 pagesEnglish languagesale 10% offe-Library read for1 day
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.
- Standard565 pagesEnglish languagesale 15% off
- Draft565 pagesEnglish languagesale 15% off
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.
- Standard34 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft32 pagesEnglish languagesale 10% offe-Library read for1 day
This European Standard specifies general safety requirements for the design, testing and production of manually operated elevators. The requirements are applicable for on- and off-shore applications of such elevators in the petroleum and petrochemical industries, and are in accordance with EU legislation.
This European Standard does not cover any other type of elevator. It is not applicable to the following types of products:
- lifting nubbins;
- lifting plugs;
- lifting subs;
- internal gripping devices;
- equipment for lifting tubular from and onto a vessel.
This list is not exclusive.
- Standard33 pagesEnglish languagesale 10% offe-Library read for1 day
- Amendment7 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft4 pagesEnglish languagesale 10% offe-Library read for1 day
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.
- Standard136 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft148 pagesEnglish languagesale 10% offe-Library read for1 day
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.
- Standard125 pagesEnglish languagesale 15% off
ISO 18647:2017 gives requirements for the design, fabrication, installation, commissioning and integrity management of modular drilling rigs on offshore fixed platforms.
The modular drilling rig includes some or all of the equipment as follows:
- drilling equipment including a derrick/mast and its controls that can be moved by skidding a drilling support structure;
- drilling support equipment which includes support facilities such as power supply/distribution system;
- mud and cement storage, mixing, monitoring and control equipment.
ISO 18647:2017 is applicable to the modular drilling equipment on offshore structures for the petroleum and natural gas industries, as follows:
- new equipment arranged in a modularized form;
- the equipment contained in several modules, each of which can be lifted and installed on to the platform, however, the equipment may be arranged within the modules as is convenient;
- the modules assembled together offshore for hook up and commissioning;
- intended for long term use on a new fixed offshore structure;
- Intended for temporary use on a number of different offshore platforms.
ISO 18647:2017 is not applicable to drilling equipment
- installed on mobile offshore units, and
- intended primarily for onshore use.
ISO 18647:2017 does not apply to those parts and functions of an offshore platform that are not directly related to drilling.
- Standard123 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft120 pagesEnglish languagesale 10% offe-Library read for1 day
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.
- Standard127 pagesEnglish languagesale 10% offe-Library read for1 day
This document specifies general safety requirements for the design, testing and production of powered elevators. The requirements are applicable for on- and off-shore applications of such elevators in the petroleum, petrochemical and natural gas industries.
This document does not cover any other type of elevator. It is not applicable to the following types of products: lifting nubbins, lifting plugs, lifting subs, internal gripping devices, equipment for lifting tubular from and onto a vessel. This list is not exclusive.
- Standard34 pagesEnglish languagesale 10% offe-Library read for1 day
- Draft32 pagesEnglish languagesale 10% offe-Library read for1 day