D03 - Gaseous Fuels

ABSTRACT
This specification presents the thermophysical property tables for methane, which are used in the calculation of the pressure-volume-temperature (PVT), thermodynamic, and transport properties of methane for process design and operations. Tables are provided for gaseous and liquid methane at specified temperature and pressure ranges. One table provides properties at the conditions of liquid-vapor equilibrium (saturation properties). The other table provides properties at selected T, p points for the equilibrium phase at those conditions. These tables apply directly only to pure gaseous methane, but are expected to be substantially useful in mathematical models and tables for the thermophysical properties of mixtures containing methane.
SCOPE
1.1 The thermophysical property tables for methane are for use in the calculation of the pressure-volume-temperature (PVT), thermodynamic, and transport properties of methane for process design and operations. Three tables are provided for gaseous and liquid methane at temperatures between 90 K and 600 K at pressures to 30 MPa. Two tables provide properties for the liquid and vapor phases at liquid-vapor equilibrium (saturation properties). The third table provides properties at selected T, p points for the equilibrium phase at those conditions. The tables were developed by the National Institute of Standards and Technology from a Standard Reference Database product REFPROP, version 10.02.  
1.2 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.

SCOPE
1.1 The thermophysical property tables for normal hydrogen are for use in the calculation of the pressure-volume-temperature (PVT), thermodynamic, and transport properties of hydrogen for process design and operations, particularly as they relate to hydrogen fuel cell applications. Tables are provided for gaseous hydrogen at temperatures between 50 K and 500 K at pressures to 500 MPa. These tables were developed by the National Institute of Standards and Technology from a Standard Reference Database product REFPROP, version 10.02.  
1.2 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.

SIGNIFICANCE AND USE
5.1 Low operating temperature fuel cells such as proton exchange membrane fuel cells require high purity hydrogen for maximum material performance and lifetime. Analysis to at least 0.05 µmol/mol concentration of total halogenated (measured as methyl fluoride) in hydrogen is necessary for assuring a feed gas of sufficient purity to satisfy fuel cell system needs as defined in ISO 14687, SAE J2719, and the California Code of Regulations, or as specified in regulatory codes.  
5.2 Although not intended for application to gases other than hydrogen, techniques within this screening method can be applied to other gaseous samples requiring total halogenated hydrocarbon content determination. The method must be validated when used to test fuels or other gaseous samples that may contain interfering compounds.
SCOPE
1.1 This practice covers the screening of organic halide content of gaseous fuels using electron capture detection. Although primarily intended for determining organic halides in hydrogen used as a fuel for fuel cell or internal combustion engine powered vehicles, this screening method can also be used, if qualified, to measure organic halides in other gaseous fuels and gaseous matrices.  
1.2 The procedure described in this method was designed to screen organic halides in hydrogen to a level much less than required by SAE J2719 and the California Code of Regulations, Title 4, Division 9, Chapter 6, Article 8, Sections 4180 – 4181. It will yield false positive result to other compounds that show response to the electron capture detector (ECD). Samples that do not pass the criteria of this screening process shall be tested to quantify and qualify the contaminants using Test Method D7892.  
1.3 The values stated in SI units are to be regarded as standard. The values given in parentheses after SI units are provided for information only and are not considered standard.  
1.4 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 limitations prior to use.  
1.5 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.

SCOPE
1.1 This terminology standard covers the compilation of terminology developed by Committee D03 on Gaseous Fuels. It does not include terms, definitions, abbreviations, acronyms, and symbols specific to only a single D03 standard in which they appear. These terms, definitions, abbreviations, acronyms, and symbols are used in:  
1.1.1 The sampling of gaseous fuels,  
1.1.2 The analysis of gaseous fuels for composition and various other physical properties, and  
1.1.3 Other practices related to the processing, transmission, and distribution of gaseous fuels.  
1.2 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.

SIGNIFICANCE AND USE
5.1 Uncontrolled oil carryover from lubricated natural gas compressors can adversely affect natural gas vehicle (NGV) performance. In some instances, small amounts of oil will accumulate in vehicle pressure regulators and slow their response. It can also affect other components of the engine fueling system. Erratic engine performance, under fueling, or engine shutdown can occur. Such incidents have been reported by operators of NGV fueling stations and vehicles.  
5.2 There is some vaporization of the lubrication (lube) oil that occurs due to compression of the gas. The oil vapor in CNG can be collected using a sorbent tube and quantified. Along with quantification of lube oil, this procedure can collect solids present in the gas.  
5.3 These methods do not separate any solids including siloxane from the compressor oil carryover or vapor.  
5.4 This practice can be applied to other gaseous samples requiring determination of compressor oil carryover provided the user’s data quality objectives are satisfied.
SCOPE
1.1 This standard practice is intended for gravimetric determination of compressor oil carryover as aerosols using either a coalescing filter method or sorbent tube method.  
1.2 The method using coalescing filters is applicable to analysis of compressor or lube oil carryover as a liquid and is intended for long term monitoring of a compressed natural gas (CNG) dispenser system.  
1.3 The method using a sorbent tube is applicable to analysis of compressor or lube oil carryover as a vapor and liquid in CNG dispenser systems present at 1 mg/kg to 500 mg/kg in a sample volume of 0.2 m3 to 0.6 m3. This method is applicable to a measurement intended to replicate the filling of a vehicle.  
1.4 This standard shall be applicable to natural gas, biogas, or renewable natural gas (RNG) that is compressed for use as a fuel for internal combustion engines in motor vehicles.  
1.5 This standard shall be applicable to natural gas, biogas, or renewable natural gas when they have been blended with hydrogen and have been compressed for use as a fuel for internal combustion engines in motor vehicles.  
1.6 The user shall determine if the volumetric measuring elements of the dispensing system are adjusted for the composition of gaseous fuel blends being delivered and those volumetric measuring elements correctly calculate the volume of fuel delivered. The users shall apply appropriate correction factors if necessary.  
1.7 Units—The values stated in SI units are to be regarded as standard.  
1.8 Mention of trade names or organizations in this standard does not constitute endorsement or recommendation. Other manufacturers of equipment or equipment models can be used.  
1.9 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 limitations prior to use.  
1.10 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.

ABSTRACT
This test method is for the determination of total sulfur in combustible fuel gases and is applicable to natural gases, manufactured gases, mixed gases, and other miscellaneous gaseous fuels. For the use of barium chloride titration following collection of sulfur dioxide by alternative procedures, ammonia, amines, substances producing water soluble cations, and fluorides will interfere with the titration. The apparatus includes the following: (1) burner, (2) chimneys, absorbers, and spray traps, (3) flow meter, (4) vacuum system, (5) air-purifying system, and (6) monometer. The schematic diagrams of the gas burner, combustion and absorption apparatus, suction system, and purified air system are provided. Reagent grade chemicals shall be used in all tests and include: (1) water, (2) denatured ethyl or isopropyl alcohol, (3) barium chloride, standard solution, (4) hydrochloric acid, (5) hydrogen peroxide, (6) iso-propanol, (7) potassium hydrogen phthalate, (8) phenolphthalein, (9) methyl orange indicator solution, (10) silver nitrate solution, (11) sodium carbonate solution, (12) sodium hydroxide solution, (13) sulfuric acid, (14) tetrahydroxyquinone indicator, and (15) thorin indicator. The procedure for the following are detailed: (1) calibration and standardization of sodium hydroxide, sulfuric acid, and barium chloride solutions, (2) preparation of apparatus, (3) sulfur determination, (4) analysis of absorbent, and (5) quality assurance. The formula of calculating the volume of gas in standard cubic feet burned during the determination and the concentration of sulfur from the results of titration are given.
SCOPE
1.1 This test method is for the determination of total sulfur in combustible fuel gases, when present in sulfur concentrations between approximately 25 and 700 mg/m3 (1 to 30 grains per 100 cubic feet). It is applicable to natural gases, manufactured gases, mixed gases, and other miscellaneous gaseous fuels.  
1.2 The values stated in inch-pound units are to be regarded as standard.  
1.3 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 limitations prior to use.  
1.4 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.

SCOPE
1.1 This specification defines the minimum fuel quality requirements for gaseous fuels consisting primarily of methane blended with volume fraction of up to 10 % hydrogen (H2) when used as an internal combustion engine fuel.  
1.2 This specification defines the criteria for blending hydrogen with natural gas, biogas, or renewable natural gas (RNG) and then compressed into compressed natural gas (CNG) for use as a fuel for internal combustion engines in motor vehicles.  
1.3 The total volume fraction of hydrogen within the fuel shall consist of hydrogen contained in the natural gas, biogas, or renewable gas and any additional hydrogen blended into the fuel mixture.  
1.4 This specification covers the needs of internal combustion engines designed for use in motor vehicles.  
1.5 This specification applies to the fuel as delivered into the on-board fuel tanks of a motor vehicle as a compressed gas.  
1.6 This specification is not a natural gas pipeline standard; those requirements are determined by national and regional tariffs.  
1.7 Units—The values stated in SI units are to be regarded as standard. The values given in parentheses after SI units are provided for information only and are not considered standard.  
1.8 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 limitations prior to use.  
1.9 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.

SIGNIFICANCE AND USE
5.1 Elemental sulfur impacts the quality of pipeline natural gas and deposits on pipeline flanges, fittings and valves, thereby impacting their performance. Natural gas suppliers and distributers require a standardized test method for measuring elemental sulfur. Some government regulators are also interested in measuring elemental sulfur since it would provide a means for assessing the contribution of elemental sulfur in pipelines to the SOx emission inventory from burning of gaseous fuels. Use of this method in concert with sulfur gas laboratory test methods such as Test Methods D4084, D4468, D5504, and D6228 or on-line methods such as D7165 or D7166 can provide users with a comprehensive sulfur compound profile for natural gas or other gaseous fuels. Other applications may include elemental sulfur in particulate deposits such as diesel exhausts.
SCOPE
1.1 This test method is primarily for the determination of elemental sulfur in natural gas pipelines, but it may be applied to other gaseous fuel pipelines and applications provided the user has validated its suitability for use. The detection range for elemental sulfur, reported as sulfur, is 0.0018 mg/L to 30 mg/L. The results may also be reported in units of mg/kg or ppm.  
1.2 The values stated in either SI units or inch-pound units are to be regarded separately as standard. The values stated in each system are not necessarily exact equivalents; therefore, to ensure conformance with the standard, each system shall be used independently of the other, and values from the two systems shall not be combined.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 This test method can be used to determine specification, or regulatory compliance to requirements, for total sulfur in gaseous fuels. In gas processing plants, sulfur can be a contaminant and must be removed before gas is introduced into gas pipelines. In petrochemical plants, sulfur is a poison for many catalysts and must be reduced to acceptable levels, usually in the range from 0.01 ppm/v to 1 ppm/v. This test method may also be used as a quality-control tool for sulfur determination in finished products, such as propane, butane, ethane, and ethylene.
SCOPE
1.1 This test method covers the determination of sulfur gaseous fuels in the range from 0.001 to 20 parts per million by volume (ppm/v).  
1.2 This test method may be extended to higher concentration by dilution.  
1.3 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.4 This standard may involve hazardous materials, operations, and equipment. 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 limitations prior to use. Specific precautionary statements are given in 7.7, 7.8, and 8.3.  
1.5 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.

SIGNIFICANCE AND USE
5.1 This test method is useful in determining the concentration of hydrogen sulfide in gaseous samples and in verifying compliance with operational needs and/or environmental limitations for H2S content. The automated performance operation of this method allows unattended measurement of H2S concentration. The user is referred to Practice D7166 for unattended on-line use of instrumentation based upon the lead acetate reaction rate method.
SCOPE
1.1 This test method covers the determination of hydrogen sulfide (H2S) in gaseous fuels. It is applicable to the measurement of H2S in natural gas, liquefied petroleum gas (LPG), substitute natural gas, landfill gas, sewage treatment off gasses, recycle gas, flare gasses, and mixtures of fuel gases. This method can also be used to measure the hydrogen sulfide concentration in carbon dioxide. Air does not interfere. The applicable range is 0.1 to 16 parts per million by volume (ppm/v) (approximately 0.1 to 22 mg/m3) and may be extended to 100 % H2S by manual or automatic volumetric dilution.  
1.2 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 limitations prior to use.  
1.3 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.

ABSTRACT
This specification covers LNG density calculation models for use in the calculation or prediction of the densities of saturated liquefied natural gas (LNG) mixtures at a specified temperature range given the pressure, temperature, and composition of the mixture. Composition restrictions for the LNGs are given for methane, nitrogen, n-butane, i-butane, and pentanes. It is assumed that hydrocarbons with carbon numbers of six or greater are not present in the LNG solution. The mathematical models presented here are the extended corresponding states model, hard sphere model, revised Klosek and McKinley model, and the cell model.
SCOPE
1.1 This specification covers Liquefied Natural Gas (LNG) density calculation models for use in the calculation or prediction of the densities of saturated LNG mixtures from 90K to 120K to within 0.1 % of true values given the pressure, temperature, and composition of the mixture.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 The methane number (MN) is a measure of the resistance of the gaseous fuel to autoignition (knock) when used in an internal combustion engine. The relative merits of gaseous fuels from different sources and having different compositions can be compared readily on the basis of their methane numbers. Therefore, the calculated methane number (MNC) is used as a parameter for determining the suitability of a gaseous fuel for internal combustion engines in both mobile and stationary applications.
SCOPE
1.1 This practice covers the method to determine the calculated methane number (MNC) of a gaseous fuel used in internal combustion engines. The basis for the method is a dynamic link library (DLL) suitable for running on computers with Microsoft Windows operating systems.  
1.2 This practice pertains to commercially available natural gas products that have been processed and are suitable for use in internal combustion engines. These fuels can be from traditional geological or renewable sources and include pipeline gas, compressed natural gas (CNG), liquefied natural gas, liquefied petroleum gas, and renewable natural gas as defined in Section 3.  
1.3 The calculation method within this practice is based on the MWM Method as defined in EN 16726, Annex A.2 The calculation method is an optimization algorithm that uses varying sequences of ternary and binary gas component tables generated from the composition of a gaseous fuel sample.3 Both the source code and a Microsoft Excel-based calculator are available for this method.  
1.4 This calculation method applies to gaseous fuels comprising of hydrocarbons from methane to hexane and greater (C6+); carbon monoxide; hydrogen; hydrogen sulfide; nitrogen; and carbon dioxide. The calculation method addresses pentanes (C5) and higher hydrocarbons and limits the individual volume fraction of C5 and C6+ to 3 % each and a combined total of 5 %. (See EN 16726, Annex A.) The calculation method is performed on a dry, oxygen-free basis.  
1.5 Units—The values stated in SI units are to be regarded as standard. Other units of measurement included in this standard are provided for information only and are not considered 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 limitations 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.

SIGNIFICANCE AND USE
5.1 On-line, at-line, in-line and other near-real time monitoring systems that measure fuel gas characteristics such as the total sulfur content are prevalent in the natural gas and fuel gas industries. The installation and operation of particular systems vary on the specific objectives, contractual obligations, process type, regulatory requirements, and internal performance requirements needed by the user. This protocol is intended to provide guidelines for standardized start-up procedures, operating procedures, and quality assurance practices for on-line, at-line, in-line and other near-real time total sulfur monitoring systems.
SCOPE
1.1 This practice is for the determination of total sulfur from gas phase sulfur-containing compounds in high methane or hydrogen content gaseous fuels using on-line/at-line instrumentation.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 Proton exchange membranes (PEM) used in fuel cells are susceptible to contamination from a number of species that can be found in hydrogen. It is critical that these contaminants be measured and verified to be present at or below the amounts stated in SAE J2719 and ISO 14687 to ensure both fuel cell longevity and optimum efficiency. Contaminant concentrations as low as single-figure ppb(v) for some species can seriously compromise the life span and efficiency of PEM fuel cells. The presence of contaminants in fuel-cell-grade hydrogen can, in some cases, have a permanent adverse impact on fuel cell efficiency and usability. It is critical to monitor the concentration of key contaminants in hydrogen during the production phase through to delivery of the fuel to a fuel cell vehicle or other PEM fuel cell application. In ISO 14687, the upper limits for the contaminants are specified. Refer to SAE J2719 (see 2.3) for specific national and regional requirements. For hydrogen fuel that is transported and delivered as a cryogenic liquid, there is additional risk of introducing impurities during transport and delivery operations. For instance, moisture can build up over time in liquid transfer lines, critical control components, and long-term storage facilities, which can lead to ice buildup within the system and subsequent blockages that pose a safety risk or the introduction of contaminants into the gas stream upon evaporation of the liquid. Users are reminded to consult Practice D7265 for critical thermophysical properties such as the ortho/para hydrogen spin isomer inversion that can lead to additional hazards in liquid hydrogen usage.
SCOPE
1.1 This test method describes contaminant determination in fuel cell grade hydrogen as specified in relevant ASTM and ISO standards using cavity ring-down spectroscopy (CRDS). This standard test method is for the measurement of one or multiple contaminants including, but not limited to, water (H2O), oxygen (O2), methane (CH4), carbon dioxide (CO2), carbon monoxide (CO), ammonia (NH3), and formaldehyde (H2CO), henceforth referred to as “analyte.”  
1.2 This test method applies to CRDS analyzers with one or multiple sensor modules (see 6.2 for definition). This test method describes sampling apparatus design, operating procedures, and quality control procedures required to obtain the stated levels of precision and accuracy.  
1.3 The values stated in either SI units or inch-pound units are to be regarded separately as standard. The values stated in each system are not necessarily exact equivalents; therefore, to ensure conformance with the standard, each system shall be used independently of the other, and values from the two systems shall not be combined.  
1.4 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 limitations prior to use.  
1.5 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.

SIGNIFICANCE AND USE
5.1 This test method can be used to measure the level of mercury in any gaseous fuel (as defined by Terminology D4150) for purposes such as determining compliance with regulations, studying the effect of various abatement procedures on mercury emissions, checking the validity of direct instrumental measurements, and verifying that mercury concentrations are below those required for gaseous fuel processing and operations.  
5.2 Adsorption of the mercury on gold-coated sorbent can remove interferences associated with the direct measurement of mercury in the presence of high concentrations of organic compounds. It preconcentrates the mercury before analysis, thereby offering measurement of ultra-low average concentrations in a gas stream over a long time span. It avoids the cumbersome use of liquid spargers with on-site sampling and eliminates contamination problems associated with the use of potassium permanganate solutions.5,6,7
SCOPE
1.1 This test method covers the determination of total mercury in gaseous fuels at concentrations down to 0.5 ng/m3. It includes separate procedures for both sampling and atomic absorption spectrophotometric determination of mercury. This procedure detects both inorganic and organic forms of mercury.  
1.2 Units—The values stated in SI units are to be regarded as the standard.  
1.3 Warning—Mercury has been designated by many regulatory agencies as a hazardous material that can cause serious medical issues. Mercury, or its vapor, has been demonstrated to be hazardous to health and corrosive to materials. Caution should be taken when handling mercury and mercury containing products. See the applicable product Safety Data Sheet (SDS) for additional information. Users should be aware that selling mercury or mercury containing products, or both, into your state or country may be prohibited by law.  
1.4 This standard does not purport to address all of the safety concerns 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 limitations prior to use.  
1.5 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.

SIGNIFICANCE AND USE
5.1 On-line, at-line, in-line, CFMS, and other near-real time monitoring systems that measure fuel gas characteristics, such as the sulfur content, are prevalent in the natural gas and fuel gas industries. The installation and operation of particular systems vary on the specific objectives, contractual obligations, process type, regulatory requirements, and internal performance requirements needed by the user. This standard is intended to provide guidelines for standardized start-up procedures, operating procedures, and quality assurance practices for on-line, at-line, in-line, CFMS, and other near-real time gas chromatographic based sulfur monitoring systems used to determine fuel gas sulfur content. For measurement of gaseous fuel properties using laboratory based methods, the user is referred to Test Methods D1072, D1945, D4084, D4468, D4810, D7833, and Practices D4626, E594.
SCOPE
1.1 This practice is for the determination of gas phase sulfur-containing compounds in high methane content gaseous fuels such as natural gas using on-line/at-line instrumentation, and continuous fuel monitors (CFMS). It has been successfully applied to other types of gaseous samples including air, digester, landfill, and refinery fuel gas. The detection range for sulfur compounds, reported as picograms sulfur, based upon the analysis of a 1 mL sample, is one hundred (100) to one million (1 000 000). This is equivalent to 0.1 to 1000 mg/m3.  
1.2 This practice does not purport to measure all sulfur species in a sample. Only gas phase compounds that are transported to an instrument under the measurement conditions selected are measured.  
1.3 Units—The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.4 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 limitations prior to use.  
1.5 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.

SIGNIFICANCE AND USE
5.1 Gaseous fuels, such as natural gas, petroleum gases and bio-gases, contain sulfur compounds that are naturally occurring or that are added as odorants for safety purposes. These sulfur compounds are odorous, toxic, corrosive to equipment, and can inhibit or destroy catalysts employed in gas processing and other end uses. Their accurate continuous measurement is important to gas processing, operation and use, and is frequently of regulatory interest.  
5.2 Small amounts (typically, total of 4 to 6 ppm(v)) of sulfur odorants are added to natural gas and other fuel gases for safety purposes. Some sulfur odorants are reactive and may be oxidized to form more stable sulfur compounds having higher odor thresholds which adversely impact the potential safety of the gas delivery systems and gas users. Gaseous fuels are analyzed for sulfur compounds and odorant levels to assist in pipeline integrity surveillance and to ensure appropriate odorant levels for public safety.  
5.3 This method offers an on-line method to continuously identify and quantify individual target sulfur species in gaseous fuel with automatic calibration and validation.
SCOPE
1.1 This test method is for on-line measurement of gas phase sulfur-containing compounds in gaseous fuels by gas chromatography (GC) and electrochemical (EC) detection. This test method is applicable to hydrogen sulfide, C1 to C4 mercaptans, sulfides, and tetrahydrothiophene (THT).  
1.1.1 Carbonyl sulfide (COS) is not measured according to this test method.  
1.1.2 The detection range for sulfur compounds is approximately from 0.1 to 100 ppm(v) (mL/m3) or 0.1 to 100 mg/m3 at 25 °C, 101.3 kPa. The detection range will vary depending on the sample injection volume, chromatographic peak separation, and the sensitivity of the specific EC detector.  
1.2 This test method describes a GC-EC method using capillary GC columns and a specific detector for natural gas and other gaseous fuels composed of mainly light (C4 and smaller) hydrocarbons. Alternative GC columns including packed columns, detector designs, and instrument parameters may be used, provided that chromatographic separation, quality control, and measurement objectives needed to comply with user or regulator needs, or both, are achieved.  
1.3 This test method does not intend to identify and measure all individual sulfur species and is mainly employed for monitoring naturally occurring reduced sulfur compounds commonly found in natural gas and fuel gases or employed as an odorant in these gases.  
1.4 This test method is typically employed in repetitive or continuous on-line monitoring of sulfur components in natural gas and fuel gases using a single sulfur calibration standard. Guidance for producing calibration curves specific to particular analytes or enhanced quality control procedures can be found in Test Methods D5504, D5623, D6228, D6968, ISO 19739, or GPA 2199.  
1.5 The test method can be used for measuring sulfur compounds listed in Table 1 in air or other gaseous matrices, provided that compounds that can interfere with the GC separation and electrochemical detection are not present.  
1.6 This test method is written as a companion to Practices D5287, D7165 and D7166.  
1.7 Units—The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.8 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 limitations prior to use.  
1.9 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 Tec...

SIGNIFICANCE AND USE
5.1 H2S measurements in natural gas are performed to ensure concentrations satisfy gas purchase contract criteria and to prevent pipeline and associated component corrosion.  
5.2 Using TDLAS for the measurement of H2S in natural gas enables a high degree of selectivity with minimal interference from common constituents in natural gas streams. The TDLAS analyzer can detect changes in concentration with a relatively rapid response compared to other methods so that operators may take swift action when designated H2S concentrations are exceeded.  
5.3 Primary applications covered in this test method are listed in 5.3.1 and 5.3.2. Each application may have differing requirements and methods for gas sampling. Additionally, different natural gas applications may require unique spectroscopic considerations.  
5.3.1 Raw natural gas is found in production, gathering sites, and inlets to gas-processing plants characterized by potentially high levels of water (H2O), carbon dioxide (CO2), H2S, and heavy hydrocarbons. Gas-conditioning plants and skids are normally used to remove H2O, CO2, H2S, and other contaminants.  
5.3.2 High-quality “sales gas” is found in transportation pipelines, natural gas distribution (utilities), and natural gas power plant inlets. The gas is characterized by a very high percentage of methane (90 to 100 %) with small quantities of other hydrocarbons and trace levels of contaminants.
SCOPE
1.1 This test method is for the online determination of hydrogen sulfide (H2S) in natural gas using tunable diode laser absorption spectroscopy (TDLAS) analyzers also known as a “TDL analyzers.” The particular wavelength for H2S measurement varies by manufacturer, typically between 1000 and 10 000 nm with an individual laser having a tunable range of less than 10 nm. The H2S concentration ranges can be anywhere from 0-5 ppm(v) to 0-90 % by volume.  
1.2 Units—The values stated in SI units are to be regarded as the standard. No other units of measurement are included in this standard. TDLAS analyzers inherently output concentrations in unitless molar ratios such as ppm(v).
Note 1: Weight-per-volume units such as milligrams or grains of H2S per cubic foot or cubic meter can be derived from ppm(v) at “standard conditions” or standard temperature and pressure.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 Low operating temperature fuel cells such as PEMFCs require high purity hydrogen for optimal performance and longevity. Organic halides and formaldehyde can react with catalyst in PEMs and non-methane hydrocarbons degrade PEM stack performance.
SCOPE
1.1 The gas chromatography/mass spectrometry (GC/MS) procedure described in this test method is used to determine concentrations of total organic halides and total non-methane hydrocarbons (TNMHC) in hydrogen by measurement of individual target halocarbons (Table 1) and hydrocarbons (including formaldehyde, Table 1 and Table 2), respectively.  
1.2 Mention of trade names in this test method does not constitute endorsement or recommendation for use. Other manufacturers’ equipment or equipment models can be used.  
1.3 Units—The values stated in SI units are to be regarded as standard.  
1.4 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 limitations prior to use.  
1.5 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.

SIGNIFICANCE AND USE
5.1 Low operating temperature fuel cells such as proton exchange membrane fuel cells (PEM-FC) require high purity hydrogen for maximum material performance and lifetime. Analysis to 0.1 part per million (ppm(v)) concentration of THCs (measured as CH4) in hydrogen is necessary for ensuring a feed gas of sufficient purity to satisfy fuel cell system needs as defined in SAE J2719 or as specified in regulatory codes.  
5.2 Dynamic dilution techniques using highly accurate mass flow controllers can be used with test samples that have THC content exceeding the upper limit of the instrument’s linear range, without the need to recalibrate the instrument using higher levels of calibration standards. The sample can be diluted with a high purity grade of hydrogen (99.999 %, so long as it contains  
5.3 Although not intended for application to gases other than hydrogen, techniques within this test method can be applied to other non-hydrocarbon gas samples requiring THC content determination. This can be achieved by using a zero gas and a calibration gas that consist of the same background gas as the actual sample. As an example, for the THC determination of nitrogen, the instrument zero point must be determined with a high purity grade of nitrogen (99.999 % and 4 in nitrogen in the appropriate range. This will correct for any interferences caused by the background gas.
SCOPE
1.1 This test method describes a procedure for total hydrocarbons (THC’s) measurement in hydrogen intended as a fuel on a methane (C1) basis. The determination of THC on a C1 basis is an analytical technique where all the hydrocarbons are assumed to have the same response as methane (CH4). Sensitivity from 0.1 parts per million by volume (ppm(v), µmol/mol) up to 1000 ppm(v) concentration is achievable. Higher concentrations can be analyzed using appropriate dilution techniques. This test method can be applied to other gaseous samples requiring analysis of trace constituents provided an assessment of potential interferences has been accomplished.  
1.2 This test method is a Flame Ionization Detector-based (FID-based) hydrocarbon analysis method without the use of separation columns. Therefore, this method does not provide speciation of individual hydrocarbons. Several varieties of instruments are manufactured and can be used for this method.  
1.2.1 This method provides a measure of THC “as CH4,” because all hydrocarbon species are quantified the same as CH4 response, which is the sole species used for calibration. Magnitude of the FID response to an atom of carbon is dependent on the chemical environment of this atom in the molecule. This method provides the THC result as if all carbon atoms are from aliphatic, aromatic, olefinic, or acetylenic compounds, where the detector response caused by these atoms is approximately relative to the number of carbon atoms present in the molecule. Other types of molecules, including those containing oxygen or chlorine atoms, will respond differently and usually much lower than the corresponding aliphatic hydrocarbon. Therefore, other methods (Test Methods D7653, D7892, or equivalent) must be utilized to determine the exact constituents of the THC response determined by this method.  
1.3 The proper handling of compressed gas cylinders containing air, nitrogen, hydrogen, or helium requires the use of gas regulators to preclude over-pressurization of any instrument component  
1.4 Units—The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.5 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 limitations prior to use.  
1.6 This international standard was developed in accordance with internationally re...

SIGNIFICANCE AND USE
5.1 Combustion of gaseous fuel containing significant siloxane concentrations results in conversion of these siloxanes to silicon dioxide (SiO2). This SiO2 accumulates on downstream equipment such as the interior of reciprocating engine cylinders (used for electricity generation and transportation applications), flame sensors, and condenser coils in residential/commercial furnaces, or post-combustion catalysts used for the removal of NO and NO2. In each of these cases, SiO2 compromises the performance of the equipment and may lead to eventual failure. Continuous measurement of siloxane concentrations enables a fuel producer to ensure their gas quality meets contractual obligations, regulatory requirements, pipeline injection tariff limits, and internal performance requirements. This method is intended to provide procedures for standardized start-up procedures, operating procedures, and quality assurance practices for on-line analysis of siloxanes using a GC-IMS analyzer.
SCOPE
1.1 This test method is for the determination of speciated siloxane concentrations in gaseous fuels using on-line Gas Chromatography Ion-Mobility Spectrometry (GC-IMS).  
1.2 Units—The values stated in SI units are to be regarded as standard. The values given in parentheses after SI units are provided for information only and are not considered standard.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 This sampling procedure is used to collect a particulate filter sample containing particulates 0.2 µm or larger in size to be used to measure the size and concentration of particulates in a gaseous fuel stream.
SCOPE
1.1 This practice is primarily for sampling particulates in gaseous fuels up to a nominal working pressure (NWP) of 70 MPa (10 152 psi) using an in-stream filter. This practice describes sampling apparatus design, operating procedures, and quality control procedures required to obtain the stated levels of precision and accuracy.  
1.2 Units—The values stated in SI units are to be regarded as standard. The values given in parentheses after SI units are provided for information only and are not considered standard.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 Moisture measurement in natural gas is performed to ensure sufficiently low levels for gas purchase contracts and to prevent corrosion. Moisture may also contribute to the formation of hydrates.  
5.2 The significance of applying TDLAS for the measurement of moisture in natural gas is TDLAS analyzers may have a very high degree of selectivity and minimal interference in many natural gas streams. Additionally, the sensing components of the analyzer are not wetted by the natural gas, limiting the potential damage from corrosives such as hydrogen sulfide (H2S) and liquid contaminants such as ethylene glycol or compressor oils. As a result, the TDLAS analyzer is able to detect changes in concentration with relatively rapid response. It should be noted that the mirrors of a TDLAS analyzer may be fouled if large quantities of condensed liquids enter the sample cell. In most cases the mirror can be cleaned without the need for recalibration or realignment.  
5.3 Primary applications covered in this method are listed in 5.3.1 – 5.3.3. Each application may have differing requirements and methods for gas sampling. Additionally, different natural gas applications may have unique spectroscopic considerations.  
5.3.1 Raw natural gas is found in production, gathering sites, and inlets to gas-processing plants characterized by potentially high levels of water (H2O), carbon dioxide (CO2), hydrogen sulfide (H2S), and heavy hydrocarbons. Gas-conditioning plants and skids are normally used to remove H2O, CO2, H2S, and other contaminants. Typical moisture concentration after dehydration is roughly 20 to 200 ppmv. Protection from liquid carryover such as heavy hydrocarbons and glycols in the sample lines is necessary to prevent liquid pooling in the cell or the sample components.  
5.3.2 Underground gas storage facilities are high-pressure caverns used to store large volumes of gas for use during peak demand. Underground storage caverns can reach pressures as high as 275 bar. ...
SCOPE
1.1 This test method covers online determination of vapor phase moisture concentration in natural gas using a tunable diode laser absorption spectroscopy (TDLAS) analyzer also known as a “TDL analyzer.” The particular wavelength for moisture measurement varies by manufacturer; typically between 1000 and 10 000 nm with an individual laser having a tunable range of less than 10 nm.  
1.2 Process stream pressures can range from 700-mbar to 700-bar gage. TDLAS is performed at pressures near atmospheric (700- to 2000-mbar gage); therefore, pressure reduction is typically required. TDLAS can be performed in vacuum conditions with good results; however, the sample conditioning requirements are different because of higher complexity and a tendency for moisture ingress and are not covered by this test method. Generally speaking, the vent line of a TDL analyzer is tolerant to small pressure changes on the order of 50 to 200 mbar, but it is important to observe the manufacturer’s published inlet pressure and vent pressure constraints. Large spikes or steps in backpressure may affect the analyzer readings.  
1.3 The typical sample temperature range is -20 to 65 °C in the analyzer cell. While sample system design is not covered by this standard, it is common practice to heat the sample transport line to around 50 °C to avoid concentration changes associated with adsorption and desorption of moisture along the walls of the sample transport line.  
1.4 The moisture concentration range is 1 to 10 000 parts per million by volume (ppmv). It is unlikely that one spectrometer cell will be used to measure this entire range. For example, a TDL spectrometer may have a maximum measurement of 1 ppmv, 100 ppmv, 1000 ppmv, or 10 000 ppmv with varying degrees of accuracy and different lower detection limits.  
1.5 TDL absorption spectroscopy measures molar ratios such as ppmv or mole percentage. Volumetric ratios (ppmv and %) are not pressure d...

SIGNIFICANCE AND USE
5.1 The composition of liquefied gaseous fuels (LNG, LPG) is important for custody transfer and production. Compositional determination is used to calculate the heating value, and it is important to ensure regulatory compliance. Compositional determination is also used to optimize the efficiency of liquefied hydrocarbon gas production and ensure the quality of the processed fluids.  
5.2 Alternatives to compositional measurement using Raman spectroscopy are described in Test Method D1945, Practice D1946, and Test Method D7833.  
5.3 The advantage of this practice over other standards stated in 5.2, is that Raman spectroscopy can determine composition by directly measuring the liquefied natural gas. Unlike chromatography, no vaporization step is necessary. Since incorrect operation of on-line vaporizers can lead to poor precision and accuracy, elimination of the vaporization step offers a significant improvement in the analysis of LNG.
SCOPE
1.1 This practice is for both on-line and laboratory instrument-based determination of composition for liquefied natural gas (LNG) using Raman spectroscopy. Although the procedures in this practice refer specifically to liquids, the basic methodology can also be applied to other light hydrocarbon mixtures in either liquid or gaseous states, provided the data quality objectives and measurement needs are met. From the composition, gas properties such as heating value and the Wobbe index may be calculated. The components commonly determined according to this test method are CH4, C2H6, C3H8, i-C4H10, n-C4H10, iC5H12, n-C5H12. Components heavier than C5 are not measured as part of this practice.
Note 1: Raman spectroscopy does not directly quantify the component percentages of noble gases; however, inert substances can be calculated indirectly by subtracting the sum of the other species from 100 %.  
1.2 Units—The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
3.1 Generally, contracts governing the pipeline transmission of natural gas contain specifications limiting the maximum concentration of water vapor allowed. Excess water vapor can cause corrosive conditions, degrading pipelines and equipment. It can also condense and freeze or form methane hydrates causing blockages. Water–vapor content also affects the heating value of natural gas, thus influencing the quality of the gas. This test method permits the determination of water content of natural gas.
SCOPE
1.1 This test method covers the determination of the water vapor content of gaseous fuels by measurement of the dew-point temperature and the calculation therefrom of the water vapor content.  
Note 1: Some gaseous fuels contain vapors of hydrocarbons or other components that easily condense into liquid and sometimes interfere with or mask the water dew point. When this occurs, it is sometimes very helpful to supplement the apparatus in Fig. 1 with an optical attachment that uniformly illuminates the dew–point mirror and also magnifies the condensate on the mirror. With this attachment it is possible, in some cases, to observe separate condensation points of water vapor, hydrocarbons, and glycolamines as well as ice points. However, if the dew point of the condensable hydrocarbons is higher than the water vapor dew point, when such hydrocarbons are present in large amounts, they may flood the mirror and obscure or wash off the water dew point. Best results in distinguishing multiple component dew points are obtained when they are not too closely spaced.
FIG. 1 Bureau of Mines Dew-Point Apparatus  
Note 2: Condensation of water vapor on the dew-point mirror may appear as liquid water at temperatures as low as 0 to −10°F (−18 to −23°C). At lower temperatures an ice point rather than a water dew point likely will be observed. The minimum dew point of any vapor that can be observed is limited by the mechanical parts of the equipment. Mirror temperatures as low as −150°F (−100°C) have been measured, using liquid nitrogen as the coolant with a thermocouple attached to the mirror, instead of a thermometer well.  
1.2 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 limitations prior to use.  
1.3 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.

SIGNIFICANCE AND USE
5.1 On-line, at-line, in-line, and other near-real time monitoring systems that measure fuel gas characteristics such as the heating value are prevalent in the natural gas and fuel gas industries. The installation and operation of particular systems vary on the specific objectives, process type, regulatory requirements, and internal performance requirements needed by the user. This protocol is intended to provide guidelines for standardized start-up procedures, operating procedures, and quality assurance practices for on-line, at-line, in-line, and other near-real time heating value monitoring systems.
SCOPE
1.1 This practice is for the determination of heating value in high methane content gaseous fuels such as natural gas using an on-line/at-line gas chromatograph.  
1.2 Units—The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 On-line, at-line, in-line, and other near-real time monitoring systems that measure fuel gas characteristics, such as heating value, are prevalent in various gaseous fuel industries and in industries either producing or using gaseous fuel in their industrial processes. The installation and operation of particular systems vary depending on process type, regulatory requirements, and the user’s objectives and performance requirements. This practice is intended to provide guidance for standardized start-up procedures, operating procedures, and quality assurance practices for calorimeter based on-line, at-line, in-line, and other near-real time heating value monitoring systems. Users employing gas chromatographic based instrumentation for measurement of gaseous fuel heating value are referred to Practice D7164.
SCOPE
1.1 This practice is for the determination of the heating value measurement of gaseous fuels using a calorimeter. Heating value determination of sample gasses containing water vapor will require vapor phase moisture measurements of the pre-combustion sample gas as well as the non-condensed gasses exiting the calorimeter. Instruments equipped with appropriate conditioners and algorithms may provide heating value results on a net or gross and dry or wet basis.  
1.2 This practice is applicable to at-line and in-line instruments that are operated from time to time on a continuous basis.  
1.3 Units—The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.4 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 limitations prior to use.  
1.5 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.

SCOPE
1.1 This specification defines the minimum fuel quality requirements for gaseous fuels consisting primarily of methane when used as an internal combustion engine fuel.  
1.2 This specification defines the criteria for compressed natural gas (CNG), liquefied natural gas (LNG), or biogas when used as a fuel for internal combustion engines in motor vehicles.  
1.3 This specification covers the needs of internal combustion engines designed for use in motor vehicles.  
1.4 Fuels that have been enriched with hydrogen are outside the scope of this specification.  
1.5 This specification applies to the fuel as delivered into the on-board fuel tanks of a motor vehicle either as a compressed gas or cryogenic liquified gas.  
1.6 This specification may serve as a guide to gaseous fuel quality requirements for internal combustion engines used in stationary applications.  
1.7 This specification is not a natural gas pipeline standard; those requirements are determined by national and regional tariffs.  
1.8 Units—The values stated in SI units are to be regarded as standard. The values given in parentheses after SI units are provided for information only and are not considered standard.  
1.9 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 limitations prior to use.  
1.10 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.

SIGNIFICANCE AND USE
5.1 The measurement of water vapor in natural gas is important because of the gas quality specifications, the corrosive nature of water vapor on pipeline materials, and the effects of water vapor on utilization equipment.  
5.2 This test method provides inexpensive field screening of water vapor. The system design is such that it may be used by nontechnical personnel with a minimum of proper training.
SCOPE
1.1 This test method covers a procedure for rapid and simple field determination of water vapor in natural gas pipelines. Available detector tubes provide a total measuring range of 0.1 to 40 mg/L, although the majority of applications will be on the lower end of this range (that is, under 0.5 mg/L). At least one manufacturer provides tubes that read directly in pounds of water per million cubic feet of gas. See Note 1.  
1.2 Detector tubes are usually subject to interferences from gases and vapors other than the target substance. Such interferences may vary among brands because of the use of different detection methods. Consult manufacturer's instructions for specific interference information. Alcohols and glycols will cause interferences on some water vapor tubes because of the presence of the hydroxyl group on those molecules.  
1.3 Units—The values stated in SI units are to be regarded as the standard.  
1.4 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 limitations prior to use.  
1.5 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.

SIGNIFICANCE AND USE
5.1 The measurement of hydrogen sulfide in natural gas is important because of gas quality specifications, the corrosive nature of H2S on pipeline materials, and the effects of H2S on utilization equipment.  
5.2 This test method provides inexpensive field screening of hydrogen sulfide. The system design is such that it may be used by nontechnical personnel with a minimum of proper training.
SCOPE
1.1 This test method covers a procedure for a rapid and simple field determination of hydrogen sulfide in natural gas pipelines. Available detector tubes provide a total measuring range of 0.5 ppm by volume up to 40 % by volume, although the majority of applications will be on the lower end of this range (that is, under 120 ppm).  
1.2 Typically, sulfur dioxide and mercaptans may cause positive interferences. In some cases, nitrogen dioxide can cause a negative interference. Most detector tubes will have a “precleanse” layer designed to remove certain interferences up to some maximum interferent level. Consult manufacturers' instructions for specific interference information.  
1.3 Units—The values stated in SI units are to be regarded as the standard.  
1.4 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 limitations prior to use.  
1.5 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.

SIGNIFICANCE AND USE
5.1 The measurement of carbon dioxide in natural gas is important, because of gas quality specifications, the corrosive nature of carbon dioxide on pipeline materials, and the affects of carbon dioxide on utilization equipment.  
5.2 This test method provides inexpensive field screening of carbon dioxide. The system design is such that it may be used by nontechnical personnel with a minimum of proper training.
SCOPE
1.1 This test method covers a rapid and simple field determination of carbon dioxide in natural gas pipelines. Available detector tubes provide a total measuring range of 100 ppm (parts per million) up to 60 % by volume, although the majority of applications will be on the lower end of this range (that is, under 5 %). At least one manufacturer provides a special kit for measurements from 10 to 100 % CO2, but the normal 100 cc hand pump is not used. See Note 1.  
Note 1: High-range carbon dioxide detector tubes will have measuring ranges in percent (%) CO2, and low-range tubes will be in parts per million (ppm). To convert percent to ppm, multiply by 10 000 (1 % = 10 000 ppm).  
1.2 Units—The values stated in SI units are regarded as standard. The inch-pound units in parentheses are for information only.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 The measurement of mercaptans in natural gas is important, because mercaptans are often added as odorants to natural gas to provide a warning property. The odor provided by the mercaptan serves to warn consumers (for example, residential use) of natural gas leaks at levels that are well below the flammable or suffocating concentration levels of natural gas in air. Field determinations of mercaptans in natural gas are important because of the tendency of the mercaptan concentration to decline over time.  
5.2 This test method provides inexpensive field screening of mercaptans. The system design is such that it may be used by nontechnical personnel, with a minimum of training.
SCOPE
1.1 This test method covers a rapid and simple field determination of mercaptans in natural gas pipelines. Available detector tubes provide a total measuring range of 0.5 to 160 ppm by volume of mercaptans, although the majority of applications will be on the lower end of this range (that is, under 20 ppm). Besides total mercaptans, detector tubes are also available for methyl mercaptan (0.5 to 100 ppm), ethyl mercaptan (0.5 to 120 ppm), and butyl mercaptan (0.5 to 30 mg/M3 or 0.1 to 8 ppm).  
Note 1: Certain detector tubes are calibrated in terms of milligrams per cubic metre (mg/M3) instead of parts per million by volume. The conversion is as follows for 25 °C (77 °F) and 760 mm Hg.
1.2 Detector tubes are usually subject to interferences from gases and vapors other than the target substance. Such interferences may vary among brands because of the use of different detection principles. Many detector tubes will have a precleanse layer designed to remove interferences up to some maximum level. Consult manufacturer's instructions for specific interference information. Hydrogen sulfide and other mercaptans are usually interferences on mercaptan detector tubes. See Section 6 for interferences of various methods of detection.  
1.3 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 limitations prior to use. For specific hazard statements, see 8.3.  
1.4 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.

SIGNIFICANCE AND USE
4.1 Flow conditioners are used for the conditioning of the turbulent flow profile of gases or liquids to reduce the ADD (velocity profile distortion) DEL (turbulence), swirl, or irregularities caused by the installation effects of piping elbows, length of pipe, valves, tees, and other such equipment or piping configurations that will affect the reading of flow measurement meters thus inducing measurement errors as a result of the flow profile of the gas or liquid not having a fully developed flow profile at the measurement point.4
SCOPE
1.1 This practice covers flow conditioners that produce a fully developed flow profile for liquid and gas phase fluid flow for circular duct sizes 1- to 60-in. (25.4- to 1525-mm) diameter and Reynolds Number (Re) ranges from transition (100) to 100 000 000. These flow conditioners can be used for any type of flow meter or development of a fully developed flow profile for other uses.  
1.2 The central single-hole configuration that is derived using fundamental screen theory is referenced as the flow conditioner described herein.  
1.3 Piping lengths upstream and downstream of a flow conditioner are considered a critical component of a flow conditioner and constitute the complete flow conditioner system.  
1.4 The values stated in inch-pound units are to be regarded as standard. The values given in parentheses are mathematical conversions to SI units that are provided for information only and are not considered standard.  
1.5 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 limitations prior to use.  
1.6 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.

SIGNIFICANCE AND USE
5.1 Many sources of natural and petroleum gases contain sulfur compounds that are odorous, corrosive, and poisonous to catalysts used in gaseous fuel processing.  
5.2 Low ppm amounts of sulfur odorants are added to natural gas and LP gases for safety purposes. Some odorants are unstable and react to form compounds having lower odor thresholds. Quantitative analysis of these odorized gases ensures that odorant injection equipment is performing to specification.  
5.3 Although not intended for application to gases other than natural gas and related fuels, this test method has been successfully applied to fuel type gases, including refinery, landfill, cogeneration, and sewage digester gas. Refinery, landfill, sewage digester, and other related fuel type gases inherently contain volatile sulfur compounds that are subject to federal, state, or local control. The methane fraction of these fuel type gases is occasionally sold to distributors of natural gas. For these reasons, both regulatory agencies and production and distribution facilities may require the accurate determination of sulfur to satisfy regulatory, production, or distribution requirements. Fuel gases are also used in energy production or are converted to new products using catalysts that are poisoned by excessive sulfur in the feed gas. Industry frequently requires measurement of sulfur in these fuel type gases to protect their catalyst investments.  
5.4 Analytical Methods—Gas chromatography (GC) is commonly used in the determination of fixed gas and organic composition of natural gas (Test Method D1945). Other standard ASTM methods for the analysis of sulfur in fuel gases include Test Methods D1072 and D4468 for total sulfur and Test Methods D4010 and D4884 for hydrogen sulfide.
SCOPE
1.1 This test method is primarily for the determination of speciated volatile sulfur-containing compounds in high methane content gaseous fuels such as natural gas. It has been successfully applied to other types of gaseous samples, including air, digester, landfill, and refinery fuel gas. The detection range for sulfur compounds, reported as picograms sulfur, is 0.01 to 1000. This is equivalent to 0.01 to 1000 mg/m3, based upon the analysis of a 1 cc sample.  
1.2 The range of this test method may be extended to higher concentration by dilution or by selection of a smaller sample loop.
Note 1: Dilution will reduce method precision.  
1.3 This test method does not purport to identify all sulfur species in a sample. Only compounds that are eluted through the selected column under the chromatographic conditions chosen are determined. The detector response to sulfur is equimolar for all sulfur compounds within the scope (1.1) of this test method. Thus, unidentified compounds are determined with equal precision to that of identified substances. Total sulfur content is determined from the total of individually quantified components.  
1.4 Units—The values stated in SI units are to be regarded as standard. The values given in parentheses after SI units are provided for information only and are not considered standard.  
1.5 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 limitations prior to use.  
1.6 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.

SIGNIFICANCE AND USE
4.1 Federal regulations (49 CFR Part 192.625) state: “A combustible gas in a distribution line must contain a natural odorant or be odorized so that at a concentration in air of one-fifth of the lower explosive limit, the gas is readily detectable by a person with a normal sense of smell.” These regulations state further that “To assure the proper concentration of odorant with this section, each operator must conduct periodic sampling of combustible gases using an instrument capable of determining the percentage of gas in air at which the odor becomes readily detectable.” Additionally, a number of states have enacted legislation that requires natural gas to be odorized so that it is detectable at concentrations less than one fifth of the lower explosive limit. See Note 1. While regulations do not specify the exact method for determining compliance, it has been documented that compliance testing must be olfactory in nature.4
Note 1: For example, Massachusetts Section 192.625 MFS Standards requires that “... a concentration of fifteen hundredths of one percent gas in the air is readily perceptible to the normal or average olfactory senses of a person...”  
4.2 This test method covers procedures to measure the odor level of natural gas by way of olfactory determination. No direct correlation may be ascertained between this test method and those methods available or under development that quantitatively measure the concentration of sulfur compounds in natural gas.  
4.3 This test method outlines general procedures to measure the odor detection levels of natural gas. It is the responsibility of persons using this test method to develop and maintain equipment and specific operating procedures to ensure public safety and compliance with all appropriate regulations.
SCOPE
1.1 This test method covers the procedures for determining the threshold detection level, readily detectable level, and odor intensity of natural gas using instruments that dilute and mix the sampled natural gas with air. The mixed gas stream is then sniffed by the operator for the purpose of determining any of these parameters for odorant in a natural gas stream.  
1.2 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 limitations prior to use.  
1.3 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.

SIGNIFICANCE AND USE
5.1 The hydrocarbon component distribution of gaseous mixtures is often required for end-use sale of this material. Applications such as chemical feedstock or fuel require precise compositional data to ensure uniform quality. Trace amounts of some hydrocarbon impurities in these materials can have adverse effects on their use and processing. Certain regulations may require use of such method.  
5.2 The component distribution data of gaseous mixtures can be used to calculate physical properties such as relative density, vapor pressure, and heating value calculations found in Practice D3588. Precision and accuracy of compositional data is extremely important when this data is used to calculate various properties of petroleum products.
SCOPE
1.1 This test method is intended to quantitatively determine the non-condensed hydrocarbon gases with carbon numbers from C1 to C5+ and non-hydrocarbon gases, such as H2, CO2, O2, N2, and CO, in gaseous samples. This test method is a companion standard test method to Test Method D1945 and Practice D1946, differing in that it incorporates use of capillary columns instead of packed columns and allows other technological differences.  
1.2 Hydrogen sulfide can be detected but may not be accurately determined by this procedure due to loss in sample containers or sample lines and possible reactions unless special precautions are taken.  
1.3 Non-hydrocarbon gases have a lower detection limit in the concentration range of 0.03 to 100 mole percent using a thermal conductivity detector (TCD), and C1 to C6 hydrocarbons have a lower detection limit in the range of 0.005 to 100 mole percent using a flame ionization detector (FID); using a TCD may increase the lower detection limit to approximately 0.03 mole percent.  
1.3.1 Hydrocarbon detection limits can be reduced with the use of pre-concentration techniques or cryogenic trapping, or both.  
1.4 This test method does not fully determine individual hydrocarbons heavier than benzene, which are grouped together as C7+. When detailed analysis is not required, the compounds with carbon number greater than C5 may be grouped as either C6+ or C7+. Accurate analysis of C5+ components depends on proper vaporization of these compounds during sampling at process unit sources as well as in the sample introduction into the analyzer in the laboratory.  
1.5 Water vapor may interfere with the C6+ analysis if a TCD detector is used.  
1.6 Helium and argon may interfere with the determination of hydrogen and oxygen respectively. Depending on the analyzer used, pentenes, if present, may either be separated or grouped with the C6+ components.  
1.7 Units—The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.8 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 limitations prior to use.  
1.9 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.

ABSTRACT
This specification covers the isobutane thermophysical property tables which are used in the calculation of the pressure-volume-temperature (PVT), thermodynamic, and transport properties of isobutane for process design and operations. Tables are provided for gaseous and liquid isobutane at temperatures between 135 and 600K at pressures to 35 MPa. These tables apply directly only to pure gaseous and liquid isobutane. However, it is expected that mathematical models and tables shall be useful for the thermophysical properties of mixtures containing isobutane, such as natural gas. These thermophysical property tables are: Thermophysical Properties of Coexisting Gaseous and Liquid Isobutane, in SI units and Thermophysical Properties of Isobutane, along isobars, in SI units.
SCOPE
1.1 The thermophysical property tables for isobutane are for use in the calculation of the pressure-volume-temperature (PVT), thermodynamic, and transport properties of isobutane for process design and operations. Two tables provide properties at the conditions of liquid-vapor equilibrium (saturation properties), one for liquid and one for vapor, at temperatures between 120 K and the critical point, 407.81 K. A third table provides properties at selected T, p points for the equilibrium phase at temperatures between 120 K and 570 K at pressures to 20 MPa. The tables were developed using the National Institute of Standards and Technology Standard Reference Database product REFPROP, version 9.1.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
4.1 Water content in fuel gas is the major factor influencing internal corrosion. Hydrates, a semisolid combination of hydrocarbons and water, will form under the proper conditions causing serious operating problems. Fuel heating value is reduced by water concentration. Water concentration levels are therefore frequently measured in natural gas systems. A common pipeline specification is 4 to 7 lb/MMSCF. This test method describes measurement of water vapor content with direct readout electronic instrumentation.
SCOPE
1.1 This test method covers the determination of the water vapor content of gaseous fuels by the use of electronic moisture analyzers. Such analyzers commonly use sensing cells based on phosphorus pentoxide, P2O5, aluminum oxide, Al2O3, or silicon sensors piezoelectric-type cells and laser based technologies.  
1.2 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 limitations prior to use.  
1.3 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.

SIGNIFICANCE AND USE
4.1 The information about the chemical composition can be used to calculate physical properties of the gas, such as heating (calorific) value and relative density. Combustion characteristics, products of combustion, toxicity, and interchangeability with other fuel gases may also be inferred from the chemical composition.
SCOPE
1.1 This practice covers the determination of the chemical composition of reformed gases and similar gaseous mixtures containing the following components: hydrogen, oxygen, nitrogen, carbon monoxide, carbon dioxide, methane, ethane, and ethylene.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
4.1 This test method is of significance for providing data for calculating physical properties of the sample, such as heating value and relative density, or for monitoring the concentrations of one or more of the components in a mixture.
SCOPE
1.1 This test method covers the determination of the chemical composition of natural gases and similar gaseous mixtures within the range of composition shown in Table 1. This test method may be abbreviated for the analysis of lean natural gases containing negligible amounts of hexanes and higher hydrocarbons, or for the determination of one or more components, as required.    
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 This test method is primarily used to monitor the concentration of oxygen in gases to verify gas quality for operational needs and contractual obligations. Oxygen content is a major factor influencing internal corrosion, fuel quality, gas quality, and user and operator safety.
SCOPE
1.1 This test method is for the determination of oxygen (O2) in gaseous fuels and fuel type gases. It is applicable to the measurement of oxygen in natural gas and other gaseous fuels. This method can be used to measure oxygen in helium, hydrogen, nitrogen, argon, carbon dioxide, mixed gases, process gases, and ambient air. The applicable range is 0.1 ppm(v) to 25 % by volume.  
1.2 Units—The values stated in either SI units or inch-pound units are to be regarded separately as standard. The values stated in each system are not necessarily exact equivalents; therefore, to ensure conformance with the standard, each system shall be used independently of the other, and values from the two systems shall not be combined.  
1.3 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 limitations prior to use.  
1.4 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.

SIGNIFICANCE AND USE
5.1 Silica generated from the combustion of gases containing siloxane compounds can damage internal combustion engines or microturbine blades, reduce heat transfer efficiency of landfill gas and biogas equipment, and poison catalytic oxidizers that are used to control regulated volatile organic compound emissions. The ability to analyze siloxanes in biologically derived fuel gases and other gaseous fuel matrices is highly desirable in order to assess the initial siloxane content and the efficacy of gas pretreatment measures.
SCOPE
1.1 This test method is primarily for gas-phase siloxane compounds present in biogas and other gaseous fuel samples at ppmv and high ppbv concentrations. It may also be applicable to low ppbv concentrations under certain circumstances.  
1.2 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 limitations prior to use.  
1.3 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.

ABSTRACT
This specification establishes the formulation of ethane thermophysical property tables for use in the calculation of the pressure-volume-temperature (PVT), thermodynamic, and transport properties of gaseous and liquid ethane for process design and operations. This table will be substantially useful in mathematical models and tables for the thermophysical properties of mixtures containing ethane, such as natural gas.
SCOPE
1.1 The thermophysical property tables for ethane are for use in the calculation of the pressure-volume-temperature (PVT), thermodynamic, and transport properties of ethane for process design and operations. Tables are provided for gaseous and liquid ethane at temperatures between 92 and 600 K at pressures to 20 MPa. Two tables provide properties at the conditions of liquid-vapor equilibrium (saturation properties). A third table provides properties at selected T, p points for the equilibrium phase at those conditions. The tables were developed by the National Institute of Standards and Technology from Standard Reference Database 23, REFPROP, version 10.0.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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.

ABSTRACT
This specification covers methyl n-amyl ketone (98 % grade) for use in paint, varnish, lacquer, and related products. The apparent specific gravity, color, distillation range, water, acidity, and purity of the material shall be tested to meet the requirements prescribed.
SCOPE
1.1 The thermophysical property tables for propane are used in calculating the pressure-volume-temperature (PVT), thermodynamic, and transport properties of propane for process design and operations. Two tables provide properties at the conditions of liquid-vapor equilibrium (saturation properties), one for liquid and one for vapor, at temperatures between 90 K and the critical point, 380 K. A third table provides properties at selected  T, p points for the equilibrium phase at temperatures between 90 K and 600 K at pressures to 20 MPa. The tables were developed by the National Institute of Standards and Technology from a Standard Reference Database product REFPROP, version 10.0.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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.

ABSTRACT
The normal butane thermophysical property tables are for use in the calculation of the pressure-volume-temperature (PVT), thermodynamic, and transport properties of normal butane for process design and operations. The preparation of the tables and supporting work was done by the National Institute of Standards and Technology (NIST) under the sponsorship of the Gas Research Institute, the American Gas Association, and the Standard Reference Data Program of NIST. These thermophysical property tables are: thermophysical properties of coexisting gaseous and liquid normal butane and thermophysical properties of normal butane.
SCOPE
1.1 The thermophysical property tables for normal butane are for use in the calculation of the pressure-volume-temperature (PVT), thermodynamic, and transport properties of normal butane for process design and operations. Two tables provide properties at the conditions of liquid-vapor equilibrium (saturation properties), one for liquid and one for vapor, at temperatures between 135 K and the critical point, 425.13 K. A third table provides properties at selected T, p points for the equilibrium phase at temperatures between 140 K and 570 K at pressures to 20 MPa. The tables were developed using the National Institute of Standards and Technology Standard Reference Database product REFPROP, version 10.0.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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.

SIGNIFICANCE AND USE
5.1 Many sources of natural gas and petroleum gases contain varying amounts and types of sulfur compounds, which are odorous, corrosive to equipment, and can inhibit or destroy catalysts used in gas processing. Their accurate measurement is essential to gas processing, operation, and utilization.  
5.2 Small amounts, typically, 1 to 4 ppmv of sulfur odorant compounds, are added to natural gas and liquefied petroleum (LP) gases for safety purposes. Some odorant compounds can be reactive and may be oxidized, forming more stable compounds having lower odor thresholds. These gaseous fuels are analyzed for sulfur odorants to help ensure appropriate odorant levels for safety.  
5.3 This test method offers a technique to determine individual sulfur species in gaseous fuel and the total sulfur content by calculation. Gas chromatography is used commonly and extensively to determine other components in gaseous fuels including fixed gas and organic components (see Test Method D1945). This test method dictates the use of a specific GC technique with one of the more common detectors for measurement.
SCOPE
1.1 This test method covers the determination of individual volatile sulfur-containing compounds in gaseous fuels by gas chromatography (GC) with a flame photometric detector (FPD) or a pulsed flame photometric detector (PFPD). The detection range for sulfur compounds is from 20 to 20 000 picograms (pg) of sulfur. This is equivalent to 0.02 to 20 mg/m3 or 0.014 to 14 ppmv of sulfur based upon the analysis of a 1 mL sample.  
1.2 This test method describes a GC method using capillary column chromatography with either an FPD or PFPD.  
1.3 This test method does not intend to identify all individual sulfur species. Total sulfur content of samples can be estimated from the total of the individual compounds determined. Unknown compounds are calculated as monosulfur-containing compounds.  
1.4 The values stated in SI units are to be regarded as standard. The values given in parentheses after SI units are provided for information only and are not considered standard.  
1.5 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 limitations prior to use.  
1.6 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.

SIGNIFICANCE AND USE
5.1 Fuel cell users have implicated trace impurities in feed gases as compromising the performance and lifespan of proton exchange membrane fuel cells (PEMFCs). PEMFCs may be damaged by the presence of some contaminants through poisoning of fuel cell electrode materials; therefore detection of these impurities at low concentrations is critical to fuel cell manufacturers and feed gas suppliers in order to support the facilities and infrastructure required for widespread applicability of fuel cells in transportation and energy production. With field-portable equipment, this test method can be used to quickly analyze hydrogen fuel for impurities at vehicle fueling stations or storage tanks used to supply stationary power plants. This test method can also be used by gas suppliers, customers, and regulatory agencies to certify hydrogen fuel quality.  
5.2 Users include hydrogen producers, gaseous fuel custody transfer stakeholders, fueling stations, fuel cell manufacturers, automotive manufacturers, regulators, and stationary fuel cell power plant operators.
SCOPE
1.1 This test method employs an FTIR gas analysis system for the determination of trace impurities in gaseous hydrogen fuels relative to the hydrogen fuel quality limits described in SAE TIR J2719 (April 2008) or in hydrogen fuel quality standards from other governing bodies. This FTIR method is used to quantify gas phase concentrations of multiple target contaminants in hydrogen fuel either directly at the fueling station or on an extracted sample that is sent to be analyzed elsewhere. Multiple contaminants can be measured simultaneously as long as they are in the gaseous phase and absorb in the infrared wavelength region. The detection limits as well as specific target contaminants for this standard were selected based upon those set forth in SAE TIR J2719.  
1.2 This test method allows the tester to determine which specific contaminants for hydrogen fuel impurities that are in the gaseous phase and are active infrared absorbers which meet or exceed the detection limits set by SAE TIR J2719 for their particular FTIR instrument. Specific target contaminants include, but are not limited to, ammonia, carbon monoxide, carbon dioxide, formaldehyde, formic acid, methane, ethane, ethylene, propane, and water. This test method may be extended to other impurities provided that they are in the gaseous phase or can be vaporized and are active infrared absorbers.  
1.3 This test method is intended for analysis of hydrogen fuels used for fuel cell feed gases or for internal combustion engine fuels. This method may also be extended to the analysis of high purity hydrogen gas used for other applications including industrial applications, provided that target impurities and required limits are also identified.  
1.4 This test method can be used to analyze hydrogen fuel sampled directly at the point-of-use from fueling station nozzles or other feed gas sources. The sampling apparatus includes a pressure regulator and metering valve to provide an appropriate gas stream for direct analysis by the FTIR spectrometer.  
1.5 This test method can also be used to analyze samples captured in storage vessels from point-of-use or other sources. Analysis of the stored samples can be performed either in a mobile laboratory near the sample source or in a standard analytical laboratory.  
1.6 A test plan should be prepared that includes (1) the specific impurity species to be measured, (2) the concentration limits for each impurity species, and (3) the determination of the minimum detectable concentration for each impurity species as measured on the apparatus before testing.  
1.7 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.7.1 Exception—All values are based upon common terms used in the industry of those particular values and when not consistent with SI units, the appropriate...

SIGNIFICANCE AND USE
5.1 This test method provides an accurate and reliable procedure to measure the total heating value of a fuel gas, on a continuous basis, which is used for regulatory compliance, custody transfer, and process control.  
5.2 Some instruments which conform to the requirements set forth in this test method can have response times on the order of 1 min or less and can be used for on-line measurement and control.  
5.3 The method is sensitive to the presence of oxygen and nonparaffin fuels. For components not listed and composition ranges that fall outside those in Table 1 and Table 2, modifications in the method and changes to the calibration gas or gasses being used may be required to obtain correct results.
SCOPE
1.1 This test method covers the determination of the heating value of natural gases and similar gaseous mixtures within the range of composition shown in Table 1, and Table 2 that covers flare components but is not intended to limit the components to be measured in flare gases.    
1.2 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 limitations prior to use.  
1.3 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.

SIGNIFICANCE AND USE
5.1 Hydrogen is delivered to fuel cell powered automotive vehicles and stationary appliances at pressures up to 87.5 MPa. The quality of hydrogen delivered is a significant factor in maximizing fuel cell efficiency and life span. Contamination can occur during the production of fuel cell feed gases, contaminating storage containers, station tubing, and fuel lines used for fuel delivery. Collection of a representative fuel sample without the introduction of contaminants even as low as parts-per-billion (ppb) per contaminant during collection is crucial for assessing the quality of fuel in real world applications.  
5.2 This practice is intended for application to high pressure, high purity hydrogen; however, the apparatus design and sampling techniques may be applicable to collection of other fuel cell feed gases. Many of the techniques used in this practice can be applied to lower pressure/lower purity gas streams.
SCOPE
1.1 This standard practice describes a sampling procedure of high pressure hydrogen at fueling stations operating at 35 or 70 megapascals (MPa) using a hydrogen quality sampling apparatus (HQSA).  
1.2 This practice does not include the analysis of the acquired sample. Applicable ASTM standards include but are not limited to test methods referenced in Section 2 of this practice.  
1.3 This practice is not intended for sampling and measuring particulate matter in high pressure hydrogen. For procedures on sampling and measuring particulate matter see ASTM D7650 and D7651.  
1.4 The values stated in SI units are standard. The values stated in inch-pounds are for information only.  
1.5 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 limitations prior to use.  
1.6 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.

SIGNIFICANCE AND USE
5.1 Low operating temperature fuel cells such as proton exchange membrane fuel cells (PEMFCs) require high purity hydrogen for maximum material performance and lifetime. Measurement of particulates in hydrogen is necessary for assuring a feed gas of sufficient purity to satisfy fuel cell and internal combustion system needs as defined in SAE J2719. The particulates in hydrogen fuel for fuel cell vehicles (FCV) and gaseous hydrogen powered internal combustion engine vehicles may adversely affect pneumatic control components, such as valves, or other critical system components. Therefore, the concentration of particulates in the hydrogen fuel should be limited as specified by ISO 14687-2, SAE J2719, or other hydrogen fuel quality specifications.  
5.2 Although not intended for application to gases other than hydrogen fuel, techniques within this test method can be applied to gas samples requiring determination of particulate concentration.
SCOPE
1.1 This test method is primarily intended for gravimetric determination of particulate concentration in hydrogen intended as a fuel for fuel cell or internal combustion engine powered vehicles. This test method describes operating and quality control procedures required to obtain data of known quality satisfying the requirements of SAE J2719. This test method can be applied to other gaseous samples requiring determination of particulates provided the user’s data quality objectives are satisfied.  
1.2 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.3 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 and health practices and determine the applicability of regulatory limitations prior to use.  
1.4 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.