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ASTM D7551-10

(Test Method)

Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases and Natural Gas by Ultraviolet Fluorescence

Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases and Natural Gas by Ultraviolet Fluorescence

SIGNIFICANCE AND USE
The sulfur content of gaseous hydrocarbons, LPG, and LNG used for fuel purposes contributes to total SOx emissions and can lead to corrosion in engine and exhaust systems. Some process catalysts used in petroleum and chemical refining can be poisoned by trace amounts of sulfur-bearing materials in the feed stocks. This test method can be used to determine the total volatile sulfur content in process feeds, to control the total volatile sulfur content in finished products and, as applicable, to meet regulatory requirements. Practice D1072 has previously been used for the measurement of total sulfur in gaseous fuels.
SCOPE
1.1 This test method covers the determination of total volatile sulfur in gaseous hydrocarbons, Liquefied Petroleum Gases (LPG) and Liquefied Natural Gas (LNG). It is applicable to analysis of natural gaseous fuels, process intermediates, final product hydrocarbons and generic gaseous fuels containing sulfur in the range of 1 to 200 mg/kg. Samples can also be tested at other total sulfur levels using either pre-concentration methods or sample dilution using a diluent gas. The methodology for preconcentration and dilution techniques is not covered in this test method. The precision statement does not apply if these techniques are used in conjunction with this test method. The diluent gas, such as UHP nitrogen, zero nitrogen or zero air, shall not have a significant total sulfur concentration.
1.2 This test method may not detect sulfur compounds that do not volatilize under the conditions of the test.
1.3 This test method covers the laboratory determination and the at-line/on-line determination of total volatile sulfur in gaseous fuels, LPG, and LNG.
1.4 This test method is applicable for total volatile sulfur determination in gaseous hydrocarbons, LPG, and LNG containing less than 0.35 mole % halogen(s).
1.5 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard..
1.6 This standard does not purport to address all of the safety concerns, if any, associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. See Sections 4.1, 7.3, 7.4, 11.2, and Section 8.

General Information

Status
Historical
Publication Date
30-Apr-2010
ICS
75.060 - Natural gas
Technical Committee
D03 - Gaseous Fuels
Current Stage
Ref Project

Relations

Referred By
ASTM D7165-22 - Standard Practice for Gas Chromatograph Based On-line/At-line Analysis for Sulfur Content of Gaseous Fuels
Effective Date
01-May-2010
Referred By
ASTM D8080-21 - Standard Specification for Compressed Natural Gas (CNG) and Liquefied Natural Gas (LNG) Used as a Motor Vehicle Fuel
Effective Date
01-May-2010
Referred By
ASTM D8488-22 - Standard Test Method for Determination of Hydrogen Sulfide (H<inf>2</inf>S) in Natural Gas by Tunable Diode Laser Spectroscopy (TDLAS)
Effective Date
01-May-2010
Referred By
ASTM D7800/D7800M-23 - Standard Test Method for Determination of Elemental Sulfur in Natural Gas
Effective Date
01-May-2010
Referred By
ASTM D8487-23 - Standard Specification for Natural Gas, Hydrogen Blends for Use as a Motor Vehicle Fuel
Effective Date
01-May-2010

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ASTM D7551-10 - Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases and Natural Gas by Ultraviolet FluorescenceASTM D7551-10 - Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases and Natural Gas by Ultraviolet Fluorescence
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ASTM D7551-10 - Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases and Natural Gas by Ultraviolet Fluorescence
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Standards Content (Sample)

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:D7551 −10
StandardTest Method for
Determination of Total Volatile Sulfur in Gaseous
Hydrocarbons and Liquefied Petroleum Gases and Natural
1
Gas by Ultraviolet Fluorescence
This standard is issued under the fixed designation D7551; the number immediately following the designation indicates the year of
original adoption or, in the case of revision, the year of last revision.Anumber in parentheses indicates the year of last reapproval.A
superscript epsilon (´) indicates an editorial change since the last revision or reapproval.
1. Scope 2. Referenced Documents
2
1.1 This test method covers the determination of total
2.1 ASTM Standards:
volatile sulfur in gaseous hydrocarbons, Liquefied Petroleum D1070Test Methods for Relative Density of Gaseous Fuels
Gases(LPG)andLiquefiedNaturalGas(LNG).Itisapplicable
D1072Test Method for Total Sulfur in Fuel Gases by
toanalysisofnaturalgaseousfuels,processintermediates,final Combustion and Barium Chloride Titration
product hydrocarbons and generic gaseous fuels containing
D1265Practice for Sampling Liquefied Petroleum (LP)
sulfur in the range of 1 to 200 mg/kg. Samples can also be Gases, Manual Method
tested at other total sulfur levels using either pre-concentration
D3588Practice for Calculating Heat Value, Compressibility
methods or sample dilution using a diluent gas. The method-
Factor, and Relative Density of Gaseous Fuels
ology for preconcentration and dilution techniques is not
D3609Practice for Calibration Techniques Using Perme-
covered in this test method. The precision statement does not
ation Tubes
apply if these techniques are used in conjunction with this test
D4150Terminology Relating to Gaseous Fuels
method. The diluent gas, such as UHP nitrogen, zero nitrogen
D4177Practice for Automatic Sampling of Petroleum and
or zero air, shall not have a significant total sulfur concentra-
Petroleum Products
tion.
D4784Specification for LNG Density Calculation Models
D5287Practice for Automatic Sampling of Gaseous Fuels
1.2 This test method may not detect sulfur compounds that
D5503Practice for Natural Gas Sample-Handling and Con-
do not volatilize under the conditions of the test.
ditioning Systems for Pipeline Instrumentation
1.3 This test method covers the laboratory determination
D5504TestMethodforDeterminationofSulfurCompounds
and the at-line/on-line determination of total volatile sulfur in
in Natural Gas and Gaseous Fuels by Gas Chromatogra-
gaseous fuels, LPG, and LNG.
phy and Chemiluminescence
D6228TestMethodforDeterminationofSulfurCompounds
1.4 This test method is applicable for total volatile sulfur
in Natural Gas and Gaseous Fuels by Gas Chromatogra-
determination in gaseous hydrocarbons, LPG, and LNG con-
phy and Flame Photometric Detection
taining less than 0.35 mole% halogen(s).
D6299Practice for Applying Statistical Quality Assurance
1.5 The values stated in SI units are to be regarded as
and Control Charting Techniques to Evaluate Analytical
standard. No other units of measurement are included in this
Measurement System Performance
standard.
D7166Practice forTotal SulfurAnalyzer Based On-line/At-
line for Sulfur Content of Gaseous Fuels
1.6 This standard does not purport to address all of the
E617Specification for Laboratory Weights and Precision
safety concerns, if any, associated with its use. It is the
Mass Standards
responsibility of the user of this standard to establish appro-
E691Practice for Conducting an Interlaboratory Study to
priate safety and health practices and determine the applica-
Determine the Precision of a Test Method
bility of regulatory limitations prior to use. See Sections 4.1,
F307Practice for Sampling Pressurized Gas for GasAnaly-
7.3, 7.4, 11.2, and Section 8.
sis
1
ThistestmethodisunderthejurisdictionofASTMCommitteeD03onGaseous
2
Fuels and is the direct responsibility of Subcommittee D03.05 on Determination of For referenced ASTM standards, visit the ASTM website, www.astm.org, or
Special Constituents of Gaseous Fuels. contact ASTM Customer Service at service@astm.org. For Annual Book of ASTM
Current edition approved May 1, 2010. Published June 2010. DOI: 10.1520/ Standards volume information, refer to the standard’s Document Summary page on
D7551–10. the ASTM website.
Copyright © ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 19428-2959. United States
1

---------------------- Page: 1 ----------------------
D7551−10
3
2.2 ASTM Manuals: ture combustion tube where the sulfur-containing compounds
ASTM MNL 7 in the sample are oxidized to SO . Water produced during the
2
4
2.3 GPA Standards: sample combustion is removed, as required, and the sample
combustiongasesarethenexposedtoasourceofcontinuousor
GPA 2166Obtaining Natural Gas Samples for Analysis by
Gas Chromatography pulsedUVlight.TheSO absorbstheenergyfromtheUVlight
2
GPA 2174
...

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ASTM D8251-23(Practice)
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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.  
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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.  
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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.  
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ASTM D7800/D7800M-23(Test Method)
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.  
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.  
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ASTM D4784-23(Specification)
Standard Specification for Liquefied Natural Gas Density Calculation Models

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.  
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Standard Test Method for Mercury Sampling and Measurement in Gaseous Fuels by Atomic Absorption Spectroscopy

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.  
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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.  
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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.
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ASTM D7904-21(Test Method)
Standard Test Method for Determination of Water Vapor (Moisture Concentration) in Natural Gas by Tunable Diode Laser Spectroscopy (TDLAS)

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.  
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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.  
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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...

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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.
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.

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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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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.  
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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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ASTM D1988-20(Test Method)
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.  
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.

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