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This document specifies requirements and tests for the construction, performance and safety of class 1,0 and class 1,5 battery powered ultrasonic gas meters (hereinafter referred to as meters), having co-axial single pipe, or two pipe connections, used to measure volumes of distributed fuel gases of the 2nd and/or 3rd family gases as given in EN 437:2021, at maximum working pressures not exceeding 0,5 bar )) and maximum actual flow rates of up to 40 m3/h over a minimum ambient temperature range of −10 °C to +40 °C, and minimum gas temperature span of 40 K. This document applies to meters where the measuring element and the register(s) are enclosed in the same case. This document applies to meters with and without built-in temperature conversion, that are installed in locations with vibration and shocks of low significance and in - closed locations (indoor or outdoor with protection as specified by the manufacturer) with condensing or with non-condensing humidity; or, if specified by the manufacturer; - open locations (outdoor without any covering) both with condensing humidity or with non-condensing humidity; and in locations with electromagnetic disturbances likely to be found in residential, commercial and light industrial use. Unless otherwise stated, all pressures given in this document are gauge pressures. Clauses 1 to 14 are for design and type testing only. Requirements for electronic indexes, batteries, valves incorporated in the meter and other additional functionalities are given in EN 16314:2013 Unless otherwise stated in a particular test, the tests are carried out on meters that include additional functionality devices intended by the manufacturer. When more than one meter type is submitted for testing, then each meter type needs to be tested against this document.

This document describes various corrosion under insulation (CUI) environments in refineries and other related industries and environments, and establishes CUI environmental categories including operating temperature ranges from −45 °C to 204 °C for topside and aboveground service only. This document specifies both established and other test methods for the assessment of coatings used for prevention of CUI for each given environment. This document also provides acceptance criteria for each CUI environment. NOTE The test results and acceptance criteria can be considered an aid in the selection of suitable coating systems. For service or peak temperatures below −45 °C an optional cryogenic test can be incorporated and for over 204 °C testing acceptance criteria can be agreed between interested parties. Additional or other test and acceptance measures are possible, but require particular agreement between the interested parties. This document covers spray-applied coatings applied on new carbon and austenitic stainless steel for use in CUI service. This document does not cover testing of sacrificial coatings, such as inorganic zinc, as these coatings can be consumed quickly in wet environments. Developing accelerated corrosion testing for what can be continuous wet service with sacrificial coatings is beyond the scope of this document. "Non-through porosity" thermal spray aluminium coatings with greater than 250 µm dry film thickness can be tested and qualified in accordance with this document. This document does not cover tape and sheet applied products for use in preventing CUI. This document does not deal with other aspects of coating degradation, such as those caused by abrasion, erosion, ultraviolet degradation or other methods that can exist given specific environment and construction methods.

This document 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 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 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 European Standard specifies the requirements and tests for the construction, performance, safety and conformity of conversion devices used to determine the energy of fuel gases described in the Table 1, including those of the 1st and 2nd families according to EN 437. The energy conversion device (ECD) considered in this standard consists of an energy calculator (EC) and is associated with the following devices and/or functions: - a volume conversion device (VCD) or a flow computer used as gas meter conversion, either conforming to EN 12405-1, or to prEN 12405-3, for high accuracy measurements; - a calorific value determination device (CVDD). Requirements for type approval tests of the devices, not included in the above-mentioned standards are described in appropriate annexes specified in Table 6. For the purpose of this European Standard, the term "volume conversion devices" (VCDs) includes flow computers (FCs). A single calculator may undertake the volume conversion functions for different metering lines.

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.