75.020 - Extraction and processing of petroleum and natural gas
ICS 75.020 Details
Extraction and processing of petroleum and natural gas
Forderung und Verarbeitung von Erdol und Erdgas
Extraction et traitement du pétrole et du gaz naturel
Pridobivanje in predelava nafte in zemeljskega plina
General Information
Frequently Asked Questions
ICS 75.020 is a classification code in the International Classification for Standards (ICS) system. It covers "Extraction and processing of petroleum and natural gas". The ICS is a hierarchical classification system used to organize international, regional, and national standards, facilitating the search and identification of standards across different fields.
There are 160 standards classified under ICS 75.020 (Extraction and processing of petroleum and natural gas). These standards are published by international and regional standardization bodies including ISO, IEC, CEN, CENELEC, and ETSI.
The International Classification for Standards (ICS) is a hierarchical classification system maintained by ISO to organize standards and related documents. It uses a three-level structure with field (2 digits), group (3 digits), and sub-group (2 digits) codes. The ICS helps users find standards by subject area and enables statistical analysis of standards development activities.
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This document:
— provides the general part of the method to calculate the greenhouse gas (GHG) emissions throughout the liquefied natural gas (LNG) chain, a means to determine their carbon footprint;
— defines preferred units of measurement and necessary conversions;
— recommends instrumentation and estimation methods to monitor and report GHG emissions. Some emissions are measured; and some are estimated.
This document covers all facilities in the LNG chain. The facilities are considered “under operation”, including emissions associated with initial start-up, maintenance, turnaround and restarts after maintenance or upset. The construction, commissioning, extension and decommissioning phases are excluded from this document but can be assessed separately.
This document covers all GHG emissions. These emissions spread across scope 1, scope 2 and scope 3 of the responsible organization. Scope 1, 2 and 3 are defined in this document. All emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive leaks and emissions associated with imported energy.
This document describes the allocation of GHG emissions to LNG and other hydrocarbon products where other products are produced (e.g. LPG, domestic gas, condensates, sulfur).
This document does not cover specific requirements on natural gas production and transport to LNG plant, liquefaction, shipping and regasification.
This document is applicable to the LNG industry.
- Standard31 pagesEnglish languagee-Library read for1 day
This document provides a method to calculate the greenhouse gas (GHG) emissions during natural gas production (onshore or offshore), gas processing and gas transport to liquefied natural gas (LNG) liquefaction plant.
NOTE It can be applied to other gases as biogas or non-traditional types of natural gas.
This document covers all facilities associated with producing natural gas, including:
— drilling (exploration, appraisal, and development) and production wells;
— gas gathering network and boosting stations (if any);
— gas processing facilities (if any), transport gas pipelines with compression stations (if any) up to inlet valve of LNG liquefaction plant.
This document covers facilities associated with producing other products (such as, but not limited to, domestic gas, condensate, Liquefied Petroleum Gas (LPG), sulphur, power export) to the extent required to allocate GHG emissions to each product.
This document covers the upstream facilities “under operation”, including emissions associated with commissioning, initial start-up and restarts after maintenance or upset. This document does not cover the exploration, construction and decommissioning phases or the losses from vegetation coverage.
This document covers all GHG emissions associated with production, process and transport of natural gas to the LNG liquefaction plant. These emissions spread across scope 1, scope 2 and scope 3 of the responsible organization, as defined in ISO 6338-1. All emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive leaks and emissions associated with imported energy. Gases covered include CO2, CH4, N2O and fluorinated gases.
This document does not cover compensation.
This document defines preferred units of measurement and necessary conversions.
This document also recommends instrumentation and estimations methods to monitor and report GHG emissions. Some emissions are measured; and some are estimated.
- Standard17 pagesEnglish languagee-Library read for1 day
This document provides a method to calculate the GHG emissions from an LNG liquefaction plant, onshore or offshore.
The frame of this document ranges from the inlet flange of the LNG plant’s inlet facilities up to and including the offloading arms to truck, ship or railcar loading. The upstream supply of gas up to the inlet flange of the inlet facilities and the distribution of LNG downstream of the loading arms are only covered in general terms.
This document covers:
— all facilities associated with producing LNG, including reception facilities, condensate unit (where applicable), pre-treatment units (including but not limited to acid gas removal, dehydration, mercury removal, heavies removal), LPG extraction and fractionation (where applicable), liquefaction, LNG storage and loading, Boil-Off-Gas handling, flare and disposal systems, imported electricity or on-site power generation and other plant utilities and infrastructure (e.g. marine and transportation facilities).
— natural gas liquefaction facilities associated with producing other products (e.g. domestic gas, condensate, LPG, sulphur, power export) to the extent required to allocate GHG emissions to the different products.
— all GHG emissions associated with producing LNG. These emissions spread across scope 1, scope 2 and scope 3 of the responsible organization. Scope 1, 2 and 3 are defined in this document. All emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive leaks and emissions associated with imported energy.
The LNG plant is considered “under operation”, including emissions associated with initial start-up, maintenance, turnaround and restarts after maintenance or upset. The construction, commissioning, extension and decommissioning phases are excluded from this document but can be assessed separately.
The emissions resulting from boil-off gas management during loading of the ship or any export vehicle are covered by this document. The emissions from a ship at berth, e.g. mast venting are not covered by this document.
This document describes the allocation of GHG emissions to LNG and other hydrocarbon products where other products are produced (e.g. LPG, domestic gas, condensates, sulphur, etc.).
This document defines preferred units of measurement and necessary conversions.
This document also recommends instrumentation and estimations methods to monitor and report GHG emissions. Some emissions are measured and some are estimated.
This document is applicable to the LNG industry.
Applications include the provision of method to calculate GHG emissions through a standardized and auditable method, a means to determine their carbon footprint.
- Standard39 pagesEnglish languagee-Library read for1 day
This document provides a method to calculate the GHG emissions from an LNG liquefaction plant, onshore or offshore.
The frame of this document ranges from the inlet flange of the LNG plant’s inlet facilities up to and including the offloading arms to truck, ship or railcar loading. The upstream supply of gas up to the inlet flange of the inlet facilities and the distribution of LNG downstream of the loading arms are only covered in general terms.
This document covers:
— all facilities associated with producing LNG, including reception facilities, condensate unit (where applicable), pre-treatment units (including but not limited to acid gas removal, dehydration, mercury removal, heavies removal), LPG extraction and fractionation (where applicable), liquefaction, LNG storage and loading, Boil-Off-Gas handling, flare and disposal systems, imported electricity or on-site power generation and other plant utilities and infrastructure (e.g. marine and transportation facilities).
— natural gas liquefaction facilities associated with producing other products (e.g. domestic gas, condensate, LPG, sulphur, power export) to the extent required to allocate GHG emissions to the different products.
— all GHG emissions associated with producing LNG. These emissions spread across scope 1, scope 2 and scope 3 of the responsible organization. Scope 1, 2 and 3 are defined in this document. All emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive leaks and emissions associated with imported energy.
The LNG plant is considered “under operation”, including emissions associated with initial start-up, maintenance, turnaround and restarts after maintenance or upset. The construction, commissioning, extension and decommissioning phases are excluded from this document but can be assessed separately.
The emissions resulting from boil-off gas management during loading of the ship or any export vehicle are covered by this document. The emissions from a ship at berth, e.g. mast venting are not covered by this document.
This document describes the allocation of GHG emissions to LNG and other hydrocarbon products where other products are produced (e.g. LPG, domestic gas, condensates, sulphur, etc.).
This document defines preferred units of measurement and necessary conversions.
This document also recommends instrumentation and estimations methods to monitor and report GHG emissions. Some emissions are measured and some are estimated.
This document is applicable to the LNG industry.
Applications include the provision of method to calculate GHG emissions through a standardized and auditable method, a means to determine their carbon footprint.
- Standard39 pagesEnglish languagee-Library read for1 day
This document provides a method to calculate the greenhouse gas (GHG) emissions during natural gas production (onshore or offshore), gas processing and gas transport to liquefied natural gas (LNG) liquefaction plant.
NOTE It can be applied to other gases as biogas or non-traditional types of natural gas.
This document covers all facilities associated with producing natural gas, including:
— drilling (exploration, appraisal, and development) and production wells;
— gas gathering network and boosting stations (if any);
— gas processing facilities (if any), transport gas pipelines with compression stations (if any) up to inlet valve of LNG liquefaction plant.
This document covers facilities associated with producing other products (such as, but not limited to, domestic gas, condensate, Liquefied Petroleum Gas (LPG), sulphur, power export) to the extent required to allocate GHG emissions to each product.
This document covers the upstream facilities “under operation”, including emissions associated with commissioning, initial start-up and restarts after maintenance or upset. This document does not cover the exploration, construction and decommissioning phases or the losses from vegetation coverage.
This document covers all GHG emissions associated with production, process and transport of natural gas to the LNG liquefaction plant. These emissions spread across scope 1, scope 2 and scope 3 of the responsible organization, as defined in ISO 6338-1. All emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive leaks and emissions associated with imported energy. Gases covered include CO2, CH4, N2O and fluorinated gases.
This document does not cover compensation.
This document defines preferred units of measurement and necessary conversions.
This document also recommends instrumentation and estimations methods to monitor and report GHG emissions. Some emissions are measured; and some are estimated.
- Standard17 pagesEnglish languagee-Library read for1 day
This document:
— provides the general part of the method to calculate the greenhouse gas (GHG) emissions throughout the liquefied natural gas (LNG) chain, a means to determine their carbon footprint;
— defines preferred units of measurement and necessary conversions;
— recommends instrumentation and estimation methods to monitor and report GHG emissions. Some emissions are measured; and some are estimated.
This document covers all facilities in the LNG chain. The facilities are considered “under operation”, including emissions associated with initial start-up, maintenance, turnaround and restarts after maintenance or upset. The construction, commissioning, extension and decommissioning phases are excluded from this document but can be assessed separately.
This document covers all GHG emissions. These emissions spread across scope 1, scope 2 and scope 3 of the responsible organization. Scope 1, 2 and 3 are defined in this document. All emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive leaks and emissions associated with imported energy.
This document describes the allocation of GHG emissions to LNG and other hydrocarbon products where other products are produced (e.g. LPG, domestic gas, condensates, sulfur).
This document does not cover specific requirements on natural gas production and transport to LNG plant, liquefaction, shipping and regasification.
This document is applicable to the LNG industry.
- Standard31 pagesEnglish languagee-Library read for1 day
This document defines terms as used in the ISO 18101 series that apply to the domain of asset-intensive industry interoperability.
- Technical specification5 pagesEnglish languagesale 15% off
This document specifies requirements and guidance for production assurance and reliability management as applicable to the assets and operations associated with exploration drilling, exploitation, processing and transport of petroleum, petrochemical and natural gas resources. It covers the assets and associated activities for upstream, midstream, downstream and petrochemical business categories. It focuses on the production assurance of oil and gas with respect to production and associated activities and covers the analysis of reliability and maintenance of the equipment. This includes a variety of associated systems and equipment in the oil and gas value chain. Production assurance addresses not only hydrocarbon production, but also associated activities such as drilling, pipeline installation and subsea intervention.
The document also supports production assurance and reliability management for lower carbon energy assets and associated operations, e.g. carbon capture and storage (CCS), hydrogen, ammonia, and wind energy. It describes the processes, activities, requirements and guidelines for systematic management, effective planning, execution and use of production assurance and reliability technology.
This document defines 12 processes, of which seven are denoted as core production assurance processes and addressed in this document. The remaining five processes are denoted as interacting processes and while they are outside the scope of this document, information is provided as to how they relate to production assurance and reliability management. The relationship of the core production assurance processes with these interacting processes, however, is within the scope of this document as the flow of information to and from these latter processes is required to ensure that production assurance requirements are fulfilled.
The document specifies how to establish and execute a production assurance programme (PAP) and a reliability management programme (RMP).
This document lists processes and activities that can be initiated to add value for the stakeholder (e.g. operator), where the selected process can depend on their business strategy and application area.
This document is intended for the following users and associated activities by their personnel:
Operators: Production assurance and reliability management activities. Related activities include project management and control, technology development, technology qualification, concept and system design, risk management (including HSE), integrity management, and maintenance management.
Contractors: Activities by the main contractor for engineering, procurement, construction, drilling, installation, operation, maintenance services, etc.
Vendors: Activities by manufacturer or supplier related to equipment design and quality management, technology development and qualification.
Authorities: Activities by regulatory bodies to ensure HSE, resource utilization and economic efficiency in operations.
Consultants: Consultancy services aimed at supporting production assurance and reliability management.
Universities: Activities associated with educating industry professionals, as well as conducting fundamental or applied research projects, when related to production assurance, reliability management, and technology development. This includes improvement of the methods and frameworks described herein.
Research institutions: Research activities related to production assurance, reliability management, and technology development. This includes equipment qualification testing and advanced engineering assessments using the methods and frameworks described herein.
- Standard112 pagesEnglish languagee-Library read for1 day
This document specifies the standard cost coding system (SCCS) that classifies costs, work hours and quantities for the assets and operations associated with the oil and gas industries including lower carbon energy activities. This document covers all life cycle phases of the assets and operations.
The SCCS is applicable to:
cost estimation;
benchmarking;
cost monitoring and reporting;
collection of quantities, work hours and cost data;
exchange of cost data among organizations;
implementation in cost systems.
This document also provides a basis for the establishment of:
cost classification relevant to cost accounting rules, specific contractual agreements, local requirements for cost reporting to national bodies, government rules and tax regulations, authorization for expenditure, billing purposes, etc.;
unique project breakdown structures (e.g. work breakdown structures, contract breakdown structures and organizational breakdown structures) or asset breakdown structures (e.g. tag or system codes and area or module breakdown structures).
This document is intended for the following users:
operators or owners;
contractors;
vendors, manufacturers or suppliers;
authorities or regulatory bodies;
benchmarking companies;
consultants.
- Standard21 pagesEnglish languagee-Library read for1 day
This document defines terms related to integration of life-cycle data for process plant installations. These terms are used by the parts in the ISO 15926 series. The following are outside the scope of this document: the reference data items that are contained in the reference data library, such as those covered in ISO/TS 15926-4:2024; the entities used in the data model, such as those covered in ISO 15926-2:2003.
- Standard28 pagesEnglish languagesale 15% off
This document specifies the standard cost coding system (SCCS) that classifies costs, work hours and quantities for the assets and operations associated with the oil and gas industries including lower carbon energy activities. This document covers all life cycle phases of the assets and operations.
The SCCS is applicable to:
cost estimation;
benchmarking;
cost monitoring and reporting;
collection of quantities, work hours and cost data;
exchange of cost data among organizations;
implementation in cost systems.
This document also provides a basis for the establishment of:
cost classification relevant to cost accounting rules, specific contractual agreements, local requirements for cost reporting to national bodies, government rules and tax regulations, authorization for expenditure, billing purposes, etc.;
unique project breakdown structures (e.g. work breakdown structures, contract breakdown structures and organizational breakdown structures) or asset breakdown structures (e.g. tag or system codes and area or module breakdown structures).
This document is intended for the following users:
operators or owners;
contractors;
vendors, manufacturers or suppliers;
authorities or regulatory bodies;
benchmarking companies;
consultants.
- Standard21 pagesEnglish languagee-Library read for1 day
This document specifies the standard cost coding system (SCCS) that classifies costs, work hours and quantities for the assets and operations associated with the oil and gas industries including lower carbon energy activities. This document covers all life cycle phases of the assets and operations. The SCCS is applicable to: cost estimation; benchmarking; cost monitoring and reporting; collection of quantities, work hours and cost data; exchange of cost data among organizations; implementation in cost systems. This document also provides a basis for the establishment of: cost classification relevant to cost accounting rules, specific contractual agreements, local requirements for cost reporting to national bodies, government rules and tax regulations, authorization for expenditure, billing purposes, etc.; unique project breakdown structures (e.g. work breakdown structures, contract breakdown structures and organizational breakdown structures) or asset breakdown structures (e.g. tag or system codes and area or module breakdown structures). This document is intended for the following users: operators or owners; contractors; vendors, manufacturers or suppliers; authorities or regulatory bodies; benchmarking companies; consultants.
- Standard13 pagesEnglish languagesale 15% off
- Standard14 pagesFrench languagesale 15% off
This document provides requirements and guidance on planning, selecting, and implementing methods and strategies for monitoring geohazards that can interact with pipelines. This document specifies requirements and recommendations for users regarding the development and initiation of monitoring processes throughout the pipeline life cycle, including the following stages: a) preliminary engineering and route selection phase; b) detailed design phase; c) construction phase; d) operation and maintenance phase. This document also describes the processes and steps for developing a suitable geohazard monitoring program (GHMP). This document applies to geohazard monitoring of new and existing onshore gathering and transportation pipelines and the right-of-way (RoW). This document does not apply to monitoring geohazards that are temporary, such as the stability of spoil piles, temporary cut slopes to facilitate pipeline construction, stability of excavation or trench wall, and access roads.
- Standard69 pagesEnglish languagesale 15% off
- Standard73 pagesFrench languagesale 15% off
This document specifies technical requirements for the structure and content of a reference data library for ISO/TS 15926-4. NOTE This document can also be applied to reference data libraries other than ISO/TS 15926-4. The following are within the scope of this document: — identification of a reference data item as specified in ISO/TS 15926-4; — information that defines a reference data item; — the way identifying and defining information is recorded using ISO 15926-2; — the reference data library that contains the reference data items necessary to record identification and defining information; — the representation of the reference data library that is defined by this document as a spreadsheet. The following are outside the scope of this document: — administrative information about the source, the history of changes, and the current status of a reference data item and a reference data library; — the way administrative information is recorded using ISO 15926-2; — the reference data library that contains the reference data items necessary to record administrative information; — defining the scope of reference data libraries within the ISO 15926 series; — methods and guidelines for implementing ISO 15926-2; — procedures for maintaining reference data libraries; — requirements for the representation of a proprietary reference data library.
- Standard33 pagesEnglish languagesale 15% off
This document provides the methods for the testing of well cement formulations to determine the dimension changes during the curing process (cement hydration) at atmospheric and elevated pressure and the stress generated by expansion in a confined environment under elevated temperature and pressure.
- Standard31 pagesEnglish languagee-Library read for1 day
This document provides the methods for the testing of well cement formulations to determine the dimension changes during the curing process (cement hydration) at atmospheric and elevated pressure and the stress generated by expansion in a confined environment under elevated temperature and pressure.
- Standard31 pagesEnglish languagee-Library read for1 day
- Amendment7 pagesEnglish languagee-Library read for1 day
This document provides the methods for the testing of well cement formulations to determine the dimension changes during the curing process (cement hydration) at atmospheric and elevated pressure and the stress generated by expansion in a confined environment under elevated temperature and pressure.
- Standard22 pagesEnglish languagesale 15% off
- Standard23 pagesFrench languagesale 15% off
- Amendment7 pagesEnglish languagee-Library read for1 day
This document provides a method to calculate the greenhouse gas (GHG) emissions during natural gas production (onshore or offshore), gas processing and gas transport to liquefied natural gas (LNG) liquefaction plant. NOTE It can be applied to other gases as biogas or non-traditional types of natural gas. This document covers all facilities associated with producing natural gas, including: — drilling (exploration, appraisal, and development) and production wells; — gas gathering network and boosting stations (if any); — gas processing facilities (if any), transport gas pipelines with compression stations (if any) up to inlet valve of LNG liquefaction plant. This document covers facilities associated with producing other products (such as, but not limited to, domestic gas, condensate, Liquefied Petroleum Gas (LPG), sulphur, power export) to the extent required to allocate GHG emissions to each product. This document covers the upstream facilities “under operation”, including emissions associated with commissioning, initial start-up and restarts after maintenance or upset. This document does not cover the exploration, construction and decommissioning phases or the losses from vegetation coverage. This document covers all GHG emissions associated with production, process and transport of natural gas to the LNG liquefaction plant. These emissions spread across scope 1, scope 2 and scope 3 of the responsible organization, as defined in ISO 6338-1. All emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive leaks and emissions associated with imported energy. Gases covered include CO2, CH4, N2O and fluorinated gases. This document does not cover compensation. This document defines preferred units of measurement and necessary conversions. This document also recommends instrumentation and estimations methods to monitor and report GHG emissions. Some emissions are measured; and some are estimated.
- Standard9 pagesEnglish languagesale 15% off
- Standard10 pagesFrench languagesale 15% off
This document specifies the set of core reference data items which can be used to record information about process plants, including oil and gas production facilities. The following are within the scope of this document: — core classes for process plants, including oil and gas production facilities; — information about a reference data item. NOTE The total set of information about a reference data item can be found in Table B.1. The following are outside the scope of this document: — data requirements for additional reference data items; — the procedures to be followed for registration and maintenance of additional reference data items.
- Technical specification26 pagesEnglish languagesale 15% off
- Standard1 pageEnglish languagesale 15% off
- Standard1 pageFrench languagesale 15% off
- Standard1 pageFrench languagesale 15% off
This document: — provides the general part of the method to calculate the greenhouse gas (GHG) emissions throughout the liquefied natural gas (LNG) chain, a means to determine their carbon footprint; — defines preferred units of measurement and necessary conversions; — recommends instrumentation and estimation methods to monitor and report GHG emissions. Some emissions are measured; and some are estimated. This document covers all facilities in the LNG chain. The facilities are considered “under operation”, including emissions associated with initial start-up, maintenance, turnaround and restarts after maintenance or upset. The construction, commissioning, extension and decommissioning phases are excluded from this document but can be assessed separately. This document covers all GHG emissions. These emissions spread across scope 1, scope 2 and scope 3 of the responsible organization. Scope 1, 2 and 3 are defined in this document. All emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive leaks and emissions associated with imported energy. This document describes the allocation of GHG emissions to LNG and other hydrocarbon products where other products are produced (e.g. LPG, domestic gas, condensates, sulfur). This document does not cover specific requirements on natural gas production and transport to LNG plant, liquefaction, shipping and regasification. This document is applicable to the LNG industry.
- Standard22 pagesEnglish languagesale 15% off
- Standard25 pagesFrench languagesale 15% off
This document provides a method to calculate the GHG emissions from an LNG liquefaction plant, onshore or offshore. The frame of this document ranges from the inlet flange of the LNG plant’s inlet facilities up to and including the offloading arms to truck, ship or railcar loading. The upstream supply of gas up to the inlet flange of the inlet facilities and the distribution of LNG downstream of the loading arms are only covered in general terms. This document covers: — all facilities associated with producing LNG, including reception facilities, condensate unit (where applicable), pre-treatment units (including but not limited to acid gas removal, dehydration, mercury removal, heavies removal), LPG extraction and fractionation (where applicable), liquefaction, LNG storage and loading, Boil-Off-Gas handling, flare and disposal systems, imported electricity or on-site power generation and other plant utilities and infrastructure (e.g. marine and transportation facilities). — natural gas liquefaction facilities associated with producing other products (e.g. domestic gas, condensate, LPG, sulphur, power export) to the extent required to allocate GHG emissions to the different products. — all GHG emissions associated with producing LNG. These emissions spread across scope 1, scope 2 and scope 3 of the responsible organization. Scope 1, 2 and 3 are defined in this document. All emissions sources are covered including flaring, combustion, cold vents, process vents, fugitive leaks and emissions associated with imported energy. The LNG plant is considered “under operation”, including emissions associated with initial start-up, maintenance, turnaround and restarts after maintenance or upset. The construction, commissioning, extension and decommissioning phases are excluded from this document but can be assessed separately. The emissions resulting from boil-off gas management during loading of the ship or any export vehicle are covered by this document. The emissions from a ship at berth, e.g. mast venting are not covered by this document. This document describes the allocation of GHG emissions to LNG and other hydrocarbon products where other products are produced (e.g. LPG, domestic gas, condensates, sulphur, etc.). This document defines preferred units of measurement and necessary conversions. This document also recommends instrumentation and estimations methods to monitor and report GHG emissions. Some emissions are measured and some are estimated. This document is applicable to the LNG industry. Applications include the provision of method to calculate GHG emissions through a standardized and auditable method, a means to determine their carbon footprint.
- Standard30 pagesEnglish languagesale 15% off
- Standard33 pagesFrench languagesale 15% off
This document enables a flexible creation of product knowledge models and data that supports systems engineering processes. The payload or design data can be exchanged across organizations or with the supply chain by combining resource description framework (RDF) triples, reference data dictionaries and a standardized set of relationships. This document is appropriate for use with the ISO 15926-series based reference data libraries, and it is applicable to the process industry, including oil, gas and power. However, manufacturing and aerospace industries can also benefit from this document. The following are within the scope of this document: — process plants in accordance with ISO 15926-1; — a methodology with low threshold for using reference data in combination with RDF triples for representing statements as defined in the ISO 15926 series; — an initial set of relationships required for process plant life-cycle representation; — a method to implement configuration management to trace back additions, changes and deletions in product and project data and enabling baselining; — data sharing, integration, exchange, and hand-over between computer systems. The following are outside the scope of this document: — serialisation methods; — definition of reference data libraries; — the syntax and format of implementations of either product data models or instance data using this document, or both; — any specific methods and guidelines other than RDF(S) for implementing ISO 15926-2.
- Technical specification72 pagesEnglish languagesale 15% off
This document provides requirements and guidance for reporting of production performance data and production loss data in the operating phase by use of production loss categorization. It supplements the principles of ISO 20815:2018, Clause E.3 and Annex G by providing additional details.
This document focusses on installations and asset elements within the upstream business category. Business categories and associated installations and plants/units, systems and equipment classes are used in line with ISO 14224:2016, Annex A.
The production loss categories given in Annex A are given at a high taxonomic level and supplements the reporting of failure and maintenance parameters as defined in ISO 14224:2016, Annex B.
- Technical specification80 pagesEnglish languagee-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 languagee-Library read for1 day
ISO 20675:2018 defines terms and describes classifications related to biogas production by anaerobic digestion, gasification from biomass and power to gas from biomass sources, biogas conditioning, biogas upgrading and biogas utilization from a safety, environmental, performance and functionality perspective, during the design, manufacturing, installation, construction, testing, commissioning, acceptance, operation, regular inspection and maintenance phases.
Biogas installations are, among others, applied at industrial plants like food and beverage industries, waste water treatment plants, waste plants, landfill sites, small scale plants next to agricultural companies and small scale household installations.
The following topics are excluded from this document:
- boilers, burners, furnaces and lightening, in case these are not specifically applied for locally produced biogas;
- gas-fuelled engines for vehicles and ships;
- the public gas grid;
- specifications to determine biomethane quality;
- transportation of compressed or liquefied biogas;
- transportation of biomass or digestate;
- assessment and determination whether biomass is sourced sustainably or not.
ISO 20675:2018 describes the following for information purposes as well:
- the parameters to determine the size (e.g. small, medium-sized, or large scale);
- the parameters to determine the type of installation (e.g. domestic, industrial);
- the parameters to describe the type of technique;
- terms and processes in order to develop health, safety and environmental protection guidelines for biogas installations.
NOTE For an explanation of the Scope, see Annex A.
- Standard28 pagesEnglish languagee-Library read for1 day
This document provides requirements and guidance for reporting of production performance data and production loss data in the operating phase by use of production loss categorization. It supplements the principles of ISO 20815:2018, Clause E.3 and Annex G by providing additional details.
This document focusses on installations and asset elements within the upstream business category. Business categories and associated installations and plants/units, systems and equipment classes are used in line with ISO 14224:2016, Annex A.
The production loss categories given in Annex A are given at a high taxonomic level and supplements the reporting of failure and maintenance parameters as defined in ISO 14224:2016, Annex B.
- Technical specification80 pagesEnglish languagee-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 languagee-Library read for1 day
ISO 20675:2018 defines terms and describes classifications related to biogas production by anaerobic digestion, gasification from biomass and power to gas from biomass sources, biogas conditioning, biogas upgrading and biogas utilization from a safety, environmental, performance and functionality perspective, during the design, manufacturing, installation, construction, testing, commissioning, acceptance, operation, regular inspection and maintenance phases.
Biogas installations are, among others, applied at industrial plants like food and beverage industries, waste water treatment plants, waste plants, landfill sites, small scale plants next to agricultural companies and small scale household installations.
The following topics are excluded from this document:
- boilers, burners, furnaces and lightening, in case these are not specifically applied for locally produced biogas;
- gas-fuelled engines for vehicles and ships;
- the public gas grid;
- specifications to determine biomethane quality;
- transportation of compressed or liquefied biogas;
- transportation of biomass or digestate;
- assessment and determination whether biomass is sourced sustainably or not.
ISO 20675:2018 describes the following for information purposes as well:
- the parameters to determine the size (e.g. small, medium-sized, or large scale);
- the parameters to determine the type of installation (e.g. domestic, industrial);
- the parameters to describe the type of technique;
- terms and processes in order to develop health, safety and environmental protection guidelines for biogas installations.
NOTE For an explanation of the Scope, see Annex A.
- Standard28 pagesEnglish languagee-Library read for1 day
This document specifies requirements for and gives guidance on the application of life cycle costing to create value for the development activities and operations associated with drilling, exploitation, processing and transport of petroleum, petrochemical and natural gas resources. This document covers facilities and associated activities within different business categories (upstream, midstream, downstream and petrochemical).
The life cycle costing process as described in this document is applicable when making decisions between competing options that are differentiated by cost and/or economic value. This document is not concerned with decision-making related to the economic performance of individual options or options differentiated by factors other than cost or economic value.
Guidance is provided on the management methodology and application of life cycle costing in support of decision-making across life cycle phases. The extent of planning and management depends on the magnitude of the costs involved, the potential value that can be created and the life cycle phase. It also provides the means of identifying cost drivers and provides a cost-control framework for these cost drivers, allowing effective cost control and optimization over the entire life of an asset.
- Standard111 pagesEnglish languagee-Library read for1 day
This document provides requirements and guidance for reporting of production performance data and production loss data in the operating phase by use of production loss categorization. It supplements the principles of ISO 20815:2018, Clause E.3 and Annex G by providing additional details. This document focusses on installations and asset elements within the upstream business category. Business categories and associated installations and plants/units, systems and equipment classes are used in line with ISO 14224:2016, Annex A. The production loss categories given in Annex A are given at a high taxonomic level and supplements the reporting of failure and maintenance parameters as defined in ISO 14224:2016, Annex B.
- Technical specification71 pagesEnglish languagesale 15% off
- Technical specification71 pagesEnglish languagesale 15% off
This document establishes the principles, specifies the requirements and provides guidance for ice management (IM) in arctic and cold regions, from the point of view of planning, engineering, implementation and documentation. Reference to arctic and cold regions in this document is deemed to include both the Arctic and other regions characterized by low ambient temperatures, sea ice, icebergs and icing conditions. These regions are often remote and lacking in marine and communications infrastructure.
Ice management to support the following in-ice activities and infrastructures are covered by this document:
— floating moored and/or dynamically positioned drilling vessels, coring vessels, production facilities and work-over vessels;
— construction and installation (includes trenching, dredging, pipe laying);
— tanker loading and other offloading operations;
— protecting subsea structures and equipment;
— seismic operations;
— oil spill response;
— bottom founded structures (fixed platforms and movable structures, including jack-ups).
This document also applies to mobilization, demobilization and construction support services, because these can be affected by ice conditions.
In view of the wide range of possible offshore operations in arctic and cold regions, this document provides guidelines, but does not present typical ice management plans for field operations.
This document does not provide requirements, recommendations or guidance pertaining to the design of structures, systems and components used in ice management, beyond the principles given. This document does not provide specific formulations for ice loads, which are covered by ISO 19906.
This document is not applicable to coastal port operations and to commercial trading vessels conducting transit or convoy operations.
- Standard104 pagesEnglish languagee-Library read for1 day
This document specifies requirements for and gives guidance on the application of life cycle costing to create value for the development activities and operations associated with drilling, exploitation, processing and transport of petroleum, petrochemical and natural gas resources. This document covers facilities and associated activities within different business categories (upstream, midstream, downstream and petrochemical).
The life cycle costing process as described in this document is applicable when making decisions between competing options that are differentiated by cost and/or economic value. This document is not concerned with decision-making related to the economic performance of individual options or options differentiated by factors other than cost or economic value.
Guidance is provided on the management methodology and application of life cycle costing in support of decision-making across life cycle phases. The extent of planning and management depends on the magnitude of the costs involved, the potential value that can be created and the life cycle phase. It also provides the means of identifying cost drivers and provides a cost-control framework for these cost drivers, allowing effective cost control and optimization over the entire life of an asset.
- Standard111 pagesEnglish languagee-Library read for1 day
This document specifies requirements for and gives guidance on the application of life cycle costing to create value for the development activities and operations associated with drilling, exploitation, processing and transport of petroleum, petrochemical and natural gas resources. This document covers facilities and associated activities within different business categories (upstream, midstream, downstream and petrochemical). The life cycle costing process as described in this document is applicable when making decisions between competing options that are differentiated by cost and/or economic value. This document is not concerned with decision-making related to the economic performance of individual options or options differentiated by factors other than cost or economic value. Guidance is provided on the management methodology and application of life cycle costing in support of decision-making across life cycle phases. The extent of planning and management depends on the magnitude of the costs involved, the potential value that can be created and the life cycle phase. It also provides the means of identifying cost drivers and provides a cost-control framework for these cost drivers, allowing effective cost control and optimization over the entire life of an asset.
- Standard102 pagesEnglish languagesale 15% off
- Standard102 pagesEnglish languagesale 15% off
- Standard108 pagesFrench languagesale 15% off
- Standard108 pagesFrench languagesale 15% off
This document defines quality management system requirements for product and service supply organizations to the petroleum, petrochemical and natural gas industries.
This document is written as a supplement to ISO 9001:2015. The supplementary requirements and guidance to ISO 9001:2015 have been developed to manage supply chain risks and opportunities associated with the petroleum, petrochemical and natural gas industries and to provide a framework for aligning requirements with complementary standards employed within the industries.
- Standard67 pagesEnglish languagee-Library read for1 day
SIGNIFICANCE AND USE
5.1 Corrosion inhibitors continue to play a key role in controlling internal corrosion associated with oil and gas production and transportation. This results primarily from the industry’s extensive use of carbon and low alloy steels, which, for many applications, are economic materials of construction that generally exhibit poor corrosion resistance. As a consequence, there is a strong reliance on inhibitor deployment for achieving cost-effective corrosion control, especially for treating long flowlines and main export pipelines (1).5
5.2 For multiphase flow, the aqueous-oil-gas interphases can take any of an infinite number of possible forms. These forms are delineated into certain classes of interfacial distribution called flow regimes. The flow regimes depend on the inclination of the pipe (that is, vertical or horizontal), flow rate (based on production rate), and flow direction (that is, upward or downward). The common flow regimes in vertical upward flow, vertical downward flow, and horizontal flow are presented in Figs. 1-3 respectively (2, 3).
5.14 To develop an inhibitor selection strategy, in addition to inhibitor efficiency, several other key performance factors need to be evaluated: (1) water/oil partitioning, (2) solubility, (3) emulsification tendency, (4) foaming tendency, (5) thermal stability, (6) toxicity, and (7) compatibility with other additives/materials.
SCOPE
1.1 This guide covers some generally accepted laboratory methodologies that are used for evaluating corrosion inhibitors for oilfield and refinery applications in well defined flow conditions.
1.2 This guide does not cover detailed calculations and methods, but rather covers a range of approaches which have found application in inhibitor evaluation.
1.3 Only those methodologies that have found wide acceptance in inhibitor evaluation are considered in this guide.
1.4 This guide is intended to assist in the selection of methodologies that can be used for evaluating corrosion inhibitors.
1.5 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
1.6 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety, health, and environmental practices and determine the applicability of regulatory requirements prior to use.
1.7 This international standard was developed in accordance with internationally recognized principles on standardization established in the Decision on Principles for the Development of International Standards, Guides and Recommendations issued by the World Trade Organization Technical Barriers to Trade (TBT) Committee.
- Guide16 pagesEnglish language
This document establishes the principles, specifies the requirements and provides guidance for ice management (IM) in arctic and cold regions, from the point of view of planning, engineering, implementation and documentation. Reference to arctic and cold regions in this document is deemed to include both the Arctic and other regions characterized by low ambient temperatures, sea ice, icebergs and icing conditions. These regions are often remote and lacking in marine and communications infrastructure.
Ice management to support the following in-ice activities and infrastructures are covered by this document:
— floating moored and/or dynamically positioned drilling vessels, coring vessels, production facilities and work-over vessels;
— construction and installation (includes trenching, dredging, pipe laying);
— tanker loading and other offloading operations;
— protecting subsea structures and equipment;
— seismic operations;
— oil spill response;
— bottom founded structures (fixed platforms and movable structures, including jack-ups).
This document also applies to mobilization, demobilization and construction support services, because these can be affected by ice conditions.
In view of the wide range of possible offshore operations in arctic and cold regions, this document provides guidelines, but does not present typical ice management plans for field operations.
This document does not provide requirements, recommendations or guidance pertaining to the design of structures, systems and components used in ice management, beyond the principles given. This document does not provide specific formulations for ice loads, which are covered by ISO 19906.
This document is not applicable to coastal port operations and to commercial trading vessels conducting transit or convoy operations.
- Standard104 pagesEnglish languagee-Library read for1 day
SIGNIFICANCE AND USE
4.1 The objective of this practice is to obtain representative samples of the steam and liquid phases as they exist in the pipeline at the sample point, without allowing steam condensation or additional liquid flashing in the separator. A significant feature of the practice is the use of a cyclone-type separator for high-efficiency phase separation which is operated at flow rates high enough to prevent significant heat loss while maintaining an internal pressure essentially the same as the pipeline pressure.
4.2 Another significant feature of the practice is to locate the sampling separator at a point on the pipeline where the two-phase flow is at least partially stratified to aid in the separation process. It is neither necessary nor possible to pass representative proportions of each phase through the sampling separator to obtain representative samples. The separator is usually attached to an appropriately oriented port to collect each specific phase – normally on top of the line for steam and at the bottom for liquid. In some cases, piping configurations can generate unusual flow regimes where the reverse is required. If the ratio of one phase to another is not extreme, it may be possible to obtain representative samples of each phase from a horizontal port on the side of the pipeline.
4.3 This practice is used whenever liquid or steam samples, or both, must be collected from a two-phase discharge for chemical analysis. This typically includes initial well-testing operations when a well is discharged to the atmosphere or routine well production when a well discharges to a fluid gathering system and power plant. The combined two-phase flow of several wells producing through a common gathering system may also be sampled in accordance with this practice.
4.4 This practice is not typically employed when individual wells produce to dedicated production separators. In these cases, the separated steam and liquid at the outlet of the production separator is samp...
SCOPE
1.1 The purpose of this practice is to obtain representative samples of liquid and steam as they exist in a pipeline transporting two-phase geothermal fluids.
1.1.1 The liquid and steam samples are collected and properly preserved for subsequent chemical analysis in the field or an off-site analytical laboratory.
1.1.2 The chemical composition data generated from the analysis of liquid and steam samples may be used for many applications important to geothermal energy exploration, development, and the long-term managed exploitation of geothermal resources. These applications include, but are not limited to, resource evaluations such as determining reservoir temperature and the origin of reservoir fluids, tracer-based measurements of production flow and enthalpy (TFT), compatibility of produced fluids with production, power generation and reinjection hardware exposed to the fluids (corrosivity and scale deposition potential), long-term reservoir monitoring during field exploitation, and environmental impact evaluations including emissions testing.
1.1.2.1 To fully utilize the chemical composition data in the applications stated in 1.1.2, specific physical data related to the two-phase discharge, wellbore, and geothermal reservoir may be required. Mathematical reconstruction of the fluid chemistry (liquid and steam) to reservoir conditions is a primary requirement in many applications. At a minimum, this requires precise knowledge of the total fluid enthalpy and pressure or temperature at the sample point. Fluid reconstruction and computations to conditions different from the sample collection point are beyond the scope of this practice.
1.2 This practice is limited to the collection of samples from two-phase flow streams at pressures greater than 70 kPa gauge (10 psig) and having a volumetric vapor fraction of at least 20 %. This practice is not applicable to single-phase flow streams such as pumped liquid disch...
- Standard9 pagesEnglish language
- Standard9 pagesEnglish language
This document defines quality management system requirements for product and service supply organizations to the petroleum, petrochemical and natural gas industries.
This document is written as a supplement to ISO 9001:2015. The supplementary requirements and guidance to ISO 9001:2015 have been developed to manage supply chain risks and opportunities associated with the petroleum, petrochemical and natural gas industries and to provide a framework for aligning requirements with complementary standards employed within the industries.
- Standard67 pagesEnglish languagee-Library read for1 day
This document defines quality management system requirements for product and service supply organizations to the petroleum, petrochemical and natural gas industries. This document is written as a supplement to ISO 9001:2015. The supplementary requirements and guidance to ISO 9001:2015 have been developed to manage supply chain risks and opportunities associated with the petroleum, petrochemical and natural gas industries and to provide a framework for aligning requirements with complementary standards employed within the industries.
- Standard53 pagesEnglish languagesale 15% off
- Standard53 pagesEnglish languagesale 15% off
- Standard55 pagesFrench languagesale 15% off
- Standard55 pagesFrench languagesale 15% off
ISO 35101:2017 describes the working environment that can be expected when operating oil and gas facilities in Arctic environments/climate. ISO 35101:2017 provides principles and generic guidelines for the design and operation of fixed and floating oil and gas facilities both onshore and offshore.
The aim of ISO 35101:2017 is to ensure optimal health, safety, human performance and decision-making conditions for people working on oil and gas facilities in Arctic conditions.
ISO 35101:2017 applies to the design and operation of new facilities and structures, and to modification of existing facilities for operation in the Arctic environment. This also includes offshore and onshore exploration and accommodation units for such activities.
ISO 35101:2017 is divided into three main parts.
- The first part (Clause 5) describes the general principles and guidelines for risk management.
- The second part (Clause 6) describes the general working environment (working environment hazards found in many workplaces and provides some threshold limit values (TLVs) and design references that can be especially challenging in Arctic conditions.
- The third part (Clause 7 to Clause 9) addresses the climatic conditions expected in the Arctic. Clause 8 describes working environment design and technical solutions, while Clause 9 describes working environment operational requirements for prevention and management of cold-related problems.
- Standard50 pagesEnglish languagee-Library read for1 day
ISO 35106:2017 specifies requirements and provides recommendations and guidance for the collection, analysis and presentation of relevant physical environmental data for activities of the petroleum and natural gas industries in arctic and cold regions. Activities include design and operations, which involve planning and actual execution.
Reference to arctic and cold regions in this document is deemed to include both the Arctic and other locations characterized by low ambient temperatures and the presence or possibility of sea ice, icebergs, shelf ice, glaciers, icing conditions, persistent snow cover, frozen surfaces of lakes and rivers, localized and rapidly changing weather systems and/or permafrost.
ISO 35106:2017 outlines requirements for a range of different operations that have been or are presently being undertaken and for existing design concepts. This document can also be used for other operations and new design concepts in arctic and cold regions as long as it is recognized that all data requirements are not necessarily addressed.
- Standard128 pagesEnglish languagee-Library read for1 day
ISO 35103:2017 gives requirements, specifications and guidelines to ensure that environmental monitoring in the offshore Arctic region is fit for purpose. The Arctic region includes the territory lying to the North of the Arctic Circle (Latitude 66°33′45.8″). This document can be applied to sub-Arctic locations which experience Arctic-like conditions and contain relevant components of a cold-climate ecosystem.
ISO 35103:2017 is applicable to all Arctic oil and gas operations from licence block acquisition through exploration, engineering design, construction, commissioning, operation, decommissioning and restoration. It covers the offshore or maritime environment, including for the purposes of this document, the fully marine and estuarine waters of the Arctic, whether frozen or ice-free. The environment includes all relevant physical, chemical and biological components. Monitoring methods for onshore (terrestrial) environments are not covered in this document, although onshore environments are included where monitoring is required at onshore locations in relation to an offshore development.
ISO 35103:2017 covers both monitoring of environmental aspects for normal, abnormal and emergency conditions, and monitoring of environmental impacts. It includes monitoring in near-field, far-field, transboundary and regional scales, but does not include global environmental monitoring.
- Standard37 pagesEnglish languagee-Library read for1 day
This document provides procedures for testing well cements and cement blends for use in the petroleum and natural gas industries in a deepwater environment, or areas with a low seafloor temperature, or areas where low well temperatures exist.
This document supplements API RP 10B-3, 2nd edition (2016), the requirements of which are applicable with the exceptions specified in this document.
This document excludes the mitigation of shallow water flow in deepwater wells.
NOTE This is addressed in API RP 65.
- Standard13 pagesEnglish languagee-Library read for1 day
This document specifies requirements and gives recommendations on the management of geohazard risks during the pipeline design, construction and operational periods.
This document is applicable to all operators and pipelines (existing and proposed/under construction).
This document applies to onshore gathering and transmission pipelines used in the petroleum and natural gas industries.
NOTE This document is not applicable to piping and pipelines within well-defined plants and facilities, such as pump or compressor stations, processing facilities or refineries. It is assumed that the facility site as a whole will be subject to a separate geohazard assessment to evaluate applicable natural and man-made hazards. Nevertheless, this document can provide useful guidance for assessing the geohazard threat to facilities, including the pipelines within the facility.
This document is applicable to all reasonable and credible natural hazards induced by natural forces and hazards induced by human activity that manifest similarly to natural hazards collectively referred to as "geological hazards" or "geohazards", or through industry as attributed to "natural forces". Geohazards covered by this document include, but are not limited to (not given in order of significance):
— mass wasting processes, including landslides, lateral spreads, rockfalls, debris flows, avalanches, and similar processes whether naturally occurring or anthropogenic;
— land subsidence and/or sinkhole formation, whether naturally occurring such as from dissolution of salt or carbonate rock formations (karst formation) or human caused, such as from underground mining or withdrawal of subsurface fluids such as groundwater and oil and gas;
— seismic hazards, such as ground shaking, fault rupture, liquefaction, flow failures and lateral spreading or associated secondary effects, such as seismically triggered landslides;
— volcanic hazards, such as lahars, pyroclastic flows, lava flows, dam break, and volcanically induced seismicity (excluding ashfall), where such hazards can be reasonably predicted;
— hydrologic processes, such as flooding, vertical scour of river bottoms, channel migration and bank erosion, channel avulsion, rapid lake drainage;
— permafrost/periglacial processes and geothermal effects, such as thermal degradation, frost heave or thaw settlement, thermal erosion, thermokarst;
— surface (overland), trench backfill, or earthwork fill erosion;
— expansion or collapsing processes caused by expansive and collapsible soils, such as glaciomarine clays, collapsible loess, etc.
This document is not applicable to atmospheric/environmental effects, such as the following:
— high winds induced from hurricanes and tornadoes and similar storms, except where such events are reasonably predictable and will induce geohazards such as landslides, erosion, etc.;
— lightning;
— forest or brush fires;
— ashfall from volcanic eruptions.
Furthermore, this document is not applicable to cascading events, where one remote event leads to a chain of events that eventually induces a geohazard near the pipeline. It is only applicable to geohazards that directly affect the pipeline or RoW.
- Standard76 pagesEnglish languagee-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.
- Standard107 pagesEnglish languagesale 15% off
- Standard107 pagesEnglish languagesale 15% off
- Standard119 pagesFrench languagesale 15% off
- Standard119 pagesFrench languagesale 15% off
This document defines the principles and methods for conformance testing of software implementations of ISO 15926. It provides guidance for developing test cases and testing procedures that cover the requirements specified in the ISO 15926 series and in different industry usage contexts, e.g. data exchange, use of reference data libraries and interface services. This document provides guidance in addition to the conformance in the parts. NOTE 1 Guidance on conformance ISO 15926 testing of complex scenarios which represent integrated interoperability is outside the scope of this document. NOTE 2 Guidance on the development of software that supports the way of file exchange in the simple scenario which represents unified interoperability is outside the scope of this document.
- Standard41 pagesEnglish languagesale 15% off
- Standard41 pagesEnglish languagesale 15% off
ISO/TS 35105:2018 provides recommendations for material selection, manufacturing and fabrication requirements, testing and qualification of steel structures and components for offshore and onshore petroleum and natural gas facilities operating in Arctic and cold environments.
ISO/TS 35105:2018 is intended to be used as a supplement to existing standards for steel structures where the particular operating conditions in Arctic regions are not sufficiently addressed.
ISO/TS 35105:2018 gives particular requirements to ensure safe operation with respect to the risk of brittle fracture at low temperatures. These requirements will affect the selection of material grade and design class as well as the technical delivery conditions for steel. They will also affect the fabrication requirements as well as testing and qualification requirements.
ISO/TS 35105:2018 also gives recommendations:
- to mitigate the operational and integrity aspects related to snow and ice accretion on topside structures;
- to take into account the particular Arctic operating conditions in corrosion assessments and requirements for corrosion protection systems;
- for particular operational requirements to ensure safe operation in Arctic regions.
The requirements in this document are applicable to any operating temperatures, but particular requirements related to de-rating (loss of strength) at high temperatures are not addressed. Limitations to the applicable minimum design temperature caused by the capability of the materials' low temperature performance can exist, but are not a limitation for the scope of this document.
As a practical guideline for the use of this document, low temperature is defined as lowest anticipated service temperature (LAST) below ?10 °C.
NOTE For determination of LAST, see 6.3.2.
- Technical specification33 pagesEnglish languagee-Library read for1 day