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ASTM D7800/D7800M-14

(Test Method)

Standard Test Method for Determination of Elemental Sulfur in Natural Gas (Withdrawn 2023)

Standard Test Method for Determination of Elemental Sulfur in Natural Gas (Withdrawn 2023)

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 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 may not be exact equivalents; therefore, each system shall be used independently of the other. Combining values from the two systems may result in non-conformance with the 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.

General Information

Status
Historical
Publication Date
31-Oct-2014
ICS
75.060 - Natural gas
Technical Committee
D03 - Gaseous Fuels
Current Stage
Ref Project

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ASTM D7800/D7800M-14 - Standard Test Method for Determination of Elemental Sulfur in Natural Gas (Withdrawn 2023)ASTM D7800/D7800M-14 - Standard Test Method for Determination of Elemental Sulfur in Natural Gas (Withdrawn 2023)
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ASTM D7800/D7800M-14 - Standard Test Method for Determination of Elemental Sulfur in Natural Gas (Withdrawn 2023)
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NOTICE: This standard has either been superseded and replaced by a new version or withdrawn.
Contact ASTM International (www.astm.org) for the latest information
Designation: D7800/D7800M − 14
Standard Test Method for
1
Determination of Elemental Sulfur in Natural Gas
This standard is issued under the fixed designation D7800/D7800M; the number immediately following the designation indicates the
year of original adoption or, in the case of revision, the year of last revision. A number in parentheses indicates the year of last
reapproval. A superscript epsilon (´) indicates an editorial change since the last revision or reapproval.
1. Scope D4468 Test Method for Total Sulfur in Gaseous Fuels by
Hydrogenolysis and Rateometric Colorimetry
1.1 This test method is primarily for the determination of
D4626 Practice for Calculation of Gas Chromatographic
elemental sulfur in natural gas pipelines, but it may be applied
Response Factors
to other gaseous fuel pipelines and applications provided the
D5287 Practice for Automatic Sampling of Gaseous Fuels
user has validated its suitability for use. The detection range for
D5504 Test Method for Determination of Sulfur Compounds
elemental sulfur, reported as sulfur, is 0.0018 to 30 mg/L. The
in Natural Gas and Gaseous Fuels by Gas Chromatogra-
results may also be reported in units of mg/kg or ppm.
phy and Chemiluminescence
1.2 The values stated in either SI units or inch-pound units
D6228 Test Method for Determination of Sulfur Compounds
are to be regarded separately as standard. The values stated in
in Natural Gas and Gaseous Fuels by Gas Chromatogra-
each system may not be exact equivalents; therefore, each
phy and Flame Photometric Detection
system shall be used independently of the other. Combining
D7165 Practice for Gas Chromatograph Based On-line/At-
values from the two systems may result in non-conformance
line Analysis for Sulfur Content of Gaseous Fuels
with the standard.
D7166 Practice for Total Sulfur Analyzer Based On-line/At-
1.3 This standard does not purport to address all of the
line for Sulfur Content of Gaseous Fuels
safety concerns, if any, associated with its use. It is the
D7551 Test Method for Determination of Total Volatile
responsibility of the user of this standard to establish appro-
Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum
priate safety and health practices and determine the applica-
Gases and Natural Gas by Ultraviolet Fluorescence
bility of regulatory limitations prior to use.
D7607 Test Method for Analysis of Oxygen in Gaseous
Fuels (Electrochemical Sensor Method)
2. Referenced Documents
E840 Practice for Using Flame Photometric Detectors in Gas
2
Chromatography
2.1 ASTM Standards:
D1072 Test Method for Total Sulfur in Fuel Gases by
2.2 ISO Documents
Combustion and Barium Chloride Titration
ISO 14532 Natural Gas—Vocabulary
D1145 Test Method for Sampling Natural Gas (Withdrawn
3
1986)
3. Terminology
D1945 Test Method for Analysis of Natural Gas by Gas
3.1 Definitions:
Chromatography
3.1.1 compressed natural gas (CNG), n—natural gas that is
D3609 Practice for Calibration Techniques Using Perme-
typically pressurized to 24.8 MPa [3,600 psi]. CNG is primar-
ation Tubes
ily used as a vehicular fuel. D4150-08 with modifications
D4084 Test Method for Analysis of Hydrogen Sulfide in
Gaseous Fuels (Lead Acetate Reaction Rate Method)
3.1.2 elemental sulfur, n—a pale yellow nonmetallic ele-
D4150 Terminology Relating to Gaseous Fuels
ment occurring in nature and found as a particulate in diesel
exhaust, natural gas, and other gaseous fuels. It exists in
several free and combined allotropic forms.
1
This test method is under the jurisdiction of ASTM Committee D03 on Gaseous
3.1.3 episulfide, n—a class of compound that contains a
Fuels and is the direct responsibility of Subcommittee D03.05 on Determination of
saturated heterocyclic ring consisting of two carbon atoms and
Special Constituents of Gaseous Fuels.
Current edition approved Nov. 1, 2014. Published November 2014. DOI: one sulfur atom. It is the sulfur analogue of an epoxide. They
10.1520/D7800_D7800M-14
are also known as thiiranes, olefin sulfides, thioalkylene
2
For referenced ASTM standards, visit the ASTM website, www.astm.org, or
oxides, and thiacyclopropanes.
contact ASTM Customer Service at service@astm.org. For Annual Book of ASTM
Standards volume information, refer to the standard’s Document Summary page on
3.1.4 liquefied natural gas (LNG), n—natural gas that has
the ASTM website.
3 been liquefied, after processing, for storage or transportation
The last approved version of this historical standard is referenced on www.ast-
m.org. purposes. ISO 14532
Copyright © ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 19428-2959. United States
1

---------------------- Page: 1 ----------------------
D7800/D7800M − 14
3.1.5 natural gas, n—a naturally occurring mixture of hy- the reaction solution. A fourth bubbler is located outside the
drocarbon and
...

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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.  
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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.  
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Standard Test Method for Determination of Elemental Sulfur in Natural Gas

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.  
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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.
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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.  
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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...

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Standard Test Method for Hydrogen Sulfide in Natural Gas Using Length-of-Stain Detector Tubes

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.
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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.  
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Standard Test Method for Water Vapor in Natural Gas Using Length-of-Stain Detector Tubes

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.  
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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.  
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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.

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Standard Test Method for Mercaptans in Natural Gas Using Length-of-Stain Detector Tubes

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.  
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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.

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