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This document provides the part of the method to calculate the GHG emissions throughout the LNG chain specific to shipping. The general requirements are covered in ISO 6338-1.

This document provides the part of the method to calculate the GHG emissions throughout the LNG chain specific to regasification. The general requirements are covered in ISO 6338-1.

This document provides requirements for the design, design verification and validation, quality control, product-functional testing, packaging, storage, and transportation of layered injection tools used in enhanced oil recovery (EOR) applications.

This document is applicable to components of layered injection tools, including mandrels, flow-control devices, and viscosity adjustment devices.

Equipment not covered by this document includes measurement and control devices, cables, and surface control valves.

The Scope clause is a mandatory element of the text.For rules on the drafting of the Scope, refer to the ISO/IEC Directives, Part 2:2021, Clause 14.

This document specifies a method for the determination of the boiling range distribution of petroleum products by capillary gas chromatography using flame ionization detection. The document is applicable to materials having a vapour pressure low enough to permit sampling at ambient temperature and a boiling range of at least 100 °C. The document is applicable to distillates with initial boiling points (IBP) above 100 °C and final boiling points (FBP) below 750 °C, for example, middle distillates and lubricating base stocks. The test method is not applicable for the analysis of petroleum or petroleum products containing low molecular weight components (for example naphtha’s, reformates, gasolines) or middle distillates like Diesel and Jet fuel. Petroleum or petroleum products containing blending components which contain heteroatoms (for example alcohols, ethers, acids, or esters) or residue are not to be analysed by this test method. NOTE For the purposes of this document, the terms “% (m/m)” and “% (V/V)” are used to represent respectively the mass fraction and the volume fraction. WARNING — The use of this document can involve hazardous materials, operations and equipment. This document does not purport to address all of the safety problems associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and to determine the applicability of regulatory limitations prior to use.

This document specifies a method for the determination of the boiling range distribution of petroleum products by capillary gas chromatography using flame ionization detection. The document is applicable to materials having a vapour pressure low enough to permit sampling at ambient temperature, and which have a boiling range of at least 100 °C. The document is applicable to materials with initial boiling points (IBP) above 100 °C and final boiling points (FBP) above 750 °C, for example, heavy distillate fuels and residuals. The method is not applicable to bituminous samples. The test method is not applicable for the analysis of petroleum or petroleum products containing low molecular weight components (for example naphthas, reformates, gasolines) or middle distillates like Diesel and Jet fuel. Petroleum or petroleum products containing blending components, which contain hetero atoms (for example alcohols, ethers, acids, or esters) or residue, are not to be analysed by this test method. NOTE For the purposes of this document, the terms “% (m/m)” and “% (V/V)” are used to represent respectively the mass fraction and the volume fraction. WARNING — The use of this document can involve hazardous materials, operations and equipment. This document does not purport to address all of the safety problems associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and to determine the applicability of regulatory limitations prior to use.

This document specifies a method for the determination of the boiling range distribution of petroleum products. The method is applicable to petroleum products and fractions with a final boiling point of 538 °C or lower at atmospheric pressure as determined by this document. This document does not apply to gasoline samples or gasoline components. The method is limited to products having a boiling range greater than 55 °C and having a vapour pressure sufficiently low to permit sampling at ambient temperature. The document describes two procedures. a) Procedure A allows a larger selection of columns and analysis conditions, such as packed and capillary columns as well as a thermal conductivity detector in addition to the flame ionization detector. Analysis times range from 14 min to 60 min. b) Procedure B is restricted to only three capillary columns and requires no sample dilution. The analysis time is reduced to about 8 min. Both procedures have been successfully applied to samples containing fatty acid methyl esters (FAME) up to 20 % (volume fraction). NOTE For the purposes of this document, the terms "% (mass fraction)" and "% (volume fraction)" are used to represent the mass fraction (µ), the volume fraction (φ) of a material.

This document specifies methods for determining whether or not a gas or gas mixture is flammable in air and whether a gas or gas mixture is more or less oxidizing than air under atmospheric conditions.

This document is intended to be used for the classification of gases and gas mixtures including the selection of gas cylinder valve outlets.

This document does not cover the safe preparation of these mixtures under pressure and at temperatures other than ambient.

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.

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.

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.

This document describes technical measures to be carried out at crossings and parallelisms of buried metal pipelines influenced by systems. It provides guidance on how the design, construction, operation, maintenance, and decommissioning phases of systems affect buried metal pipelines. Electromagnetic, DC interference and thermal influences on pipeline coatings are described.

Acceptable levels of interference are discussed.

Guidance is provided for calculation methods to establish an acceptable separation distance between the pipeline and the source of interference.

The following aspects are not covered in this document:

Interference from other AC sources

Contractual responsibilities

Personnel safety.