D03.12 - On-Line/At-Line Analysis of Gaseous Fuels

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 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 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 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
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.

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
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 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 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, 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 utilization, and is frequently of regulatory interest.  
5.2 Small amounts (typically, total of 4 to 6 ppmv) 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 lower 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 technique 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 volatile 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 covered in this test method.  
1.1.2 The detection range for sulfur compounds is approximately from 0.1 to 100 ppmv (mL/m3) or 0.1 to 100 mg/m3. The detection range may vary depending on the sample injection volume, chromatographic peak separation and the sensitivity to the specific EC detector.  
1.2 This test method describes a GC-EC method employing packed GC columns and a specific detector for natural gas and other gaseous fuel composed of mainly light (C4 and smaller) hydrocarbons. Alternative GC 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 The 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. Need for a multipoint calibration curve or quality control procedures can be satisfied by making use of procedures delineated in Test Methods D5504, D5623, D6228, D6968, ISO 19739, or GPA 2199.  
1.5 The test method can be used for measurement of all sulfur compounds listed in Table 1 in air or other gaseous matrices, provided that no compounds that can interfere with the GC separation and electrochemical detection are present.  
1.6 This test method is written as a companion to Practices D5287, D7165 and D7166.  
1.7 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.8 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 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 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.

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 and health practices and determine the applicability of regulatory limitations prior to use.

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 and Practices D4626, E594.
SCOPE
1.1 This practice is for the determination of volatile 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 cc sample, is one hundred (100) to one million (1,000,000). This is equivalent to 0.1 to 1,000 mg/m3.  
1.2 This practice does not purport to measure all sulfur species in a sample. Only volatile compounds that are transported to an instrument under the measurement conditions selected are measured.  
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 practice 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 practice to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.

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 volatile 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 and health practices and determine the applicability of regulatory limitations prior to use.

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 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 and health practices and determine the applicability of regulatory limitations prior to use.

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 pppmv. 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 dep...

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, 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 utilization, and is frequently of regulatory interest.  
5.2 Small amounts (typically, total of 4 to 6 ppmv) 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 lower 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 technique 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 volatile 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 covered in this test method.  
1.1.2 The detection range for sulfur compounds is approximately from 0.1 to 100 ppmv (mL/m3) or 0.1 to 100 mg/m3. The detection range may vary depending on the sample injection volume, chromatographic peak separation and the sensitivity to the specific EC detector.  
1.2 This test method describes a GC-EC method employing packed GC columns and a specific detector for natural gas and other gaseous fuel composed of mainly light (C4 and smaller) hydrocarbons. Alternative GC 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 The 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. Need for a multipoint calibration curve or quality control procedures can be satisfied by making use of procedures delineated in Test Methods D5504, D5623, D6228, D6968, ISO 19739, or GPA 2199.  
1.5 The test method can be used for measurement of all sulfur compounds listed in Table 1 in air or other gaseous matrices, provided that no compounds that can interfere with the GC separation and electrochemical detection are present.  
1.6 This test method is written as a companion to Practices D5287, D7165 and D7166.  
1.7 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.  
1.8 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 and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
5.1 The composition of liquefied gas 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 standard over existing standards mentioned in 5.2 above, 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 standard practice is for both on-line and laboratory instrument-based determination of composition for liquefied natural gas (LNG) using Raman spectroscopy. The basic methodology can also be applied to other light hydrocarbon mixtures in either liquid or gaseous states, if the needs of the application are met, although the rest of this practice refers specifically to liquids. 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, neo-C5H12, N2, O2. The applicable range of this standard is 200 ppmv to 100 mol %. 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, inerts can be calculated indirectly by subtracting the sum of the other species from 100 %.  
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.

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 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.

SIGNIFICANCE AND USE
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 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.

SIGNIFICANCE AND USE
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 and Practices D4626, E594.
SCOPE
1.1 This practice is for the determination of volatile 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 cc sample, is one hundred (100) to one million (1,000,000). This is equivalent to 0.1 to 1,000 mg/m3.  
1.2 This practice does not purport to measure all sulfur species in a sample. Only volatile compounds that are transported to an instrument under the measurement conditions selected are measured.  
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 practice 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 practice to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
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 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.

SIGNIFICANCE AND USE
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 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 and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
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 volatile 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 and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
Gaseous fuels, such as natural gas, petroleum gases and bio-gases, contain varying amounts and types of sulfur compounds. These sulfur compounds are generally odorous, corrosive to equipment, and can inhibit or destroy catalysts employed in gas processing and end use, such as those used in fuel cell. Their accurate on-line measurement is essential to gas processing, operation and utilization, and of regulatory interest.
Small amounts (typically, total 4-6 PPMv) of sulfur odorants are added to natural gas and other fuel gases for safety purposes. Some sulfur odorants can be reactive, and may be oxidized, forming more stable sulfur compounds having lower odor thresholds. These gaseous fuels are analyzed for sulfur odorants to help in monitoring and to ensure appropriate odorant levels for public safety.
This method offers an on-line technique 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 volatile sulfur-containing compounds in gaseous fuels by gas chromatography (GC) and electrochemical (EC) detection. The test method is applicable to hydrogen sulfide, C1-C4 mercaptans, sulfides and tetrahydrothiophene (THT).
1.1.1 Carbonyl sulfide (COS) is not covered in this test method.
1.1.2 The detection range for sulfur compounds is approximately from 0.1 to 100 PPMv or 0.1 to 100 mg/m3. The detection range may vary depending on the sample injection volume, chromatographic peak separation and the sensitivity of specific EC detector.
1.2 This test method describes a GC-EC method employing packed GC columns and a specific detector as an illustration for natural gas and other gaseous fuel containing mainly light hydrocarbons. Alternative GC columns, detector designs and instrument parameters may be used for the same analysis or for different types of gaseous fuel, provided that appropriate chromatographic separation and optimal detection of these compounds can be achieved.  
1.3 This test method does not intend to identify and measure all individual sulfur species, and is mainly employed for monitoring natural sulfur and sulfur odorant compounds commonly found in fuel gases or employed as an odorous warning agent in fuel gases.
1.4 The test method is normally employed for repetitive on-line monitoring of sulfur components in fuel gases with a single sulfur standard. The test method may be employed for laboratory-quality measurement with more extensive calibration. (See Test Methods D 5504, D 5623, D 6228, D 6968, ISO 19739, ISO 6326-2, and GPA 2199.)
1.5 The test method can be used for measurement of all listed sulfur compounds in air or other gases, provided that no compound, which can interfere with the GC separation and electrochemical detection, is present.
1.6 This test method is written in conjunction with Practices D 5287, D 7165 and D 7166.
1.7 The values stated in SI units are to be regarded as standard. No other units of measurement are included in this standard.
1.8 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 and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
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 D 7164.
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 The values stated in SI units are to be regarded as the standard. The values given in parentheses are for information only.
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 and health practices and determine the applicability of regulatory limitations prior to use.

SCOPE
1.1 This practice is for the determination of volatile 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 cc sample, is one hundred (100) to one million (1,000,000). This is equivalent to 0.1 to 1,000 mg/m3.
1.2 This practice does not purport to measure all sulfur species in a sample. Only volatile compounds that are transported to an instrument under the measurement conditions selected are measured.
1.3 The values stated in SI units are standard. The values stated in inch-pound units are for information only.
1.4 This practice 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 practice to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
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 volatile 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 standard. Values stated in other units 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 and health practices and determine the applicability of regulatory limitations prior to use.

SIGNIFICANCE AND USE
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 The values stated in SI units are standard. Values stated in other units 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 and health practices and determine the applicability of regulatory limitations prior to use.