Natural gas — Vocabulary
Gaz naturel — Vocabulaire
ISO 14532:2001 (E/F)
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© ISO 2001
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1 Scope 1
2 Terms and definitions 1
2.1 General definitions 1
2.1.1 Natural gas 1
2.1.2 Pipeline network 6
2.2 Measurement methods 7
2.2.1 General definitions 7
2.2.2 Specific methods 9
2.3 Sampling 11
2.3.1 Sampling methods 11
2.3.2 Sampling devices 12
2.3.3 Conditioning device 13
2.3.4 Other definitions 14
2.4 Analytical systems 15
2.5 Analysis 18
2.5.1 Metrology 18
2.5.2 Calibration and quality control 21
2.5.3 Gas analysis 24
22.214.171.124 General definitions 24
126.96.36.199 Analysed components 26
188.8.131.52 Trace component [constituent] 28
184.108.40.206 Analyser response 31
220.127.116.11 Calibration gas mixtures 35
18.104.22.168.1 General definitions from metrology 35
22.214.171.124.2 Definitions relevant to gas mixtures 38
2.5.4 Statistics 39
2.6 Physical and chemical properties 40
2.6.1 Reference conditions 40
2.6.2 Behaviour of ideal and real gas 41
2.6.3 Density 43
2.6.4 Combustion properties 44
2.6.5 Dew points 46
126.96.36.199 Water dew point 46
188.8.131.52 Hydrocarbon dew point 47
2.6.6 Other definitions 47
2.7 Interchangeability 48
2.8 Odorization 49
Annex A (informative) Subscripts, symbols and units 51
ISO (the International Organization for Standardization) is a worldwide federation of national standards bodies (ISO member bodies). The work of preparing International Standards is normally carried out through ISO technical committees. Each member body interested in a subject for which a technical committee has been established has the right to be represented on that committee. International organizations, governmental and non-governmental, in liaison with ISO, also take part in the work. ISO collaborates closely with the International Electrotechnical Commission (lEC) on all matters of electrotechnical standardization.
International Standards are drafted in accordance with the rules given in the ISO/IEC Directives, Part 3.
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Attention is drawn to the possibility that some of the elements of this International Standard may be the subject of patent rights. ISO shall not be held responsible for identifying any or all such patent rights.
International Standard ISO 14532 was prepared by Joint Technical Committee ISO/TC 193, Natural gas.
ISO Technical Committee 193, Natural Gas, was established in May, 1989, with the task of creating new International Standards, and updating existing International Standards relevant to natural gas. This includes gas analysis, direct measurement of properties, quality designation and traceability.
In these activities, a comprehensive and uniform review of the definitions, symbols and abbreviations used in the International Standards was not previously systematically pursued. The development of International Standards with terminology created to suit specific purposes often resulted in the detriment of uniformity and cohesiveness between International Standards.
Thus, there is the need for harmonization of the terminology used in the International Standards pertaining to natural gas. The intention of this International Standard is to incorporate the reviewed definitions into the ISO/TC 193 source International Standards.
The aim is to create a coherent body of International Standards which support each other with regard to their definitions. Common and unambiguous terms and definitions used throughout all International Standards is the starting point for the understanding and application of every International Standard.
The presentation of this International Standard has been arranged to facilitate its use as follows:
— Major headings pertain to specific fields of the natural gas industry. All definitions which fall under these headings, as gleaned from ISO International Standards issued through ISO/TC 193, are listed under that heading. A review of the Contents will serve to facilitate finding specific terms.
— Notes are given under numerous definitions where it was deemed important to give informative guidance for a given definition. The notes are not considered a part of the definition.
© !SO 2001 - All rights reserved/Tous droits reserves vii
Natural gas — Vocabulary
This International Standard establishes the terms, definitions, symbols and abbreviations used in the field of natural gas.
The terms and definitions have been reviewed and studied in order to cover all aspects of any particular term with input from other sources such as European standards from CEN (The European Committee for standardization), national standards and existing definitions in the IGU dictionary of the gas industry.
2 Terms and definitions
2.1 General definitions
For the purposes of this International Standard, the following terms and definitions apply.
2.1.1 Natural gas
184.108.40.206 natural gas NG
complex gaseous mixture of hydrocarbons, primarily methane, but generally also including ethane, propane and higher hydrocarbons in much smaller amounts and some non-combustible gases, such as nitrogen and carbon dioxide
NOTE 1 Natural gas generally also includes minor amounts of trace constituents.
NOTE 2 Natural gas is produced and processed from the raw gas or liquefied natural gas and, if required, blended to the extent suitable for direct use (e.g. as gaseous fuel).
NOTE 3 Natural gas remains in the gaseous state under the temperature and pressure conditions normally found in service.
NOTE 4 Natural gas consists predominantly of methane (mole fraction greater than 0,70), and has a superior calorific value normally within the range 30 MJ/m3 to 45 MJ/m3. It contains also ethane (typically up to 0,10 mole fraction), propane, butanes and higher alkanes in steadily decreasing amounts. Nitrogen and carbon dioxide are the principal non-combustible components, each present at levels which typically vary from less than 0,01 mole fraction to 0.20 mole fraction.
Natural gas is processed from the raw gas so as to be suitable for use as industrial, commercial, residential fuel or as a chemical feedstock. The processing is intended to reduce the contents of potentially corrosive components, such as hydrogen sulfide and carbon dioxide, and of other components, such as water and higher hydrocarbons, potentially condensable in the transmission and distribution of the gas. Hydrogen sulfide, organic sulfur compounds and water are then reduced to trace amounts, and high carbon dioxide contents are likely to be reduced to below 0,05 mole fraction.
Natural gas is normally technically free from aerosol, liquid and particulate matter.
In some circumstances, natural gas may be blended with town gas or coke oven gas, in which case hydrogen and carbon monoxide can be present in amounts up to 0,10 mole fraction and 0,03 mole fraction respectively. In this case, small amounts of ethylene may also be present.
Natural gas may also be blended with LPG/air mixtures, in which case oxygen can be present, and the levels of propane and butanes can be considerably enhanced.
NOTE 5 Pipeline quality natural gas is one which has been processed so as to be suitable for direct use as industrial, commercial, residential fuel or as a chemical feed stock.
The processing is intended to reduce the corrosive and toxicity effects of certain components, and to avoid condensation of water or hydrocarbons in the transmission and distribution of the gas.
Hydrogen sulphide and water should only be present in trace amounts, and high carbon dioxide content is likely to be reduced.
220.127.116.11 raw gas
unprocessed gas taken from well heads, through gathering lines, to processing or treating facilities
NOTE Raw gas can also be partially processed wellhead gas taken from basic upstream processing facilities.
substitute natural gas
manufactured or blended gas which is interchangeable in its properties with natural gas
manufactured gas synthetic gas
gas which has been treated and may contain components which are not typical of natural gas
NOTE Manufactured (synthetic) gases may contain substantial amounts of chemical species which are not typical of natural gases or common species found in atypical proportions as in the case of wet and sour gases.
Manufactured gases fall into two distinct categories, as follows:
a) those which are intended as synthetic or substitute natural gases, and which closely match true natural gases in both composition and properties;
b) those which, whether or not intended to replace or enhance natural gas in service, do not closely match natural gases in composition.
In the case a), the composition of the manufactured gas may be such that the gas is indistinguishable from that of a possible true natural gas. However, more often a manufactured gas, even if it contains inert and lower hydrocarbon gases in satisfactory proportions, does not exhibit the distinctive hydrocarbon "tail" of a true natural gas and may additionally contain small but significant amounts of non-alkane hydrocarbons.
Case b) includes gases such as town gas, (undiluted) coke oven gas, and LPG/air mixtures, none of which is compositionally similar to a true natural gas (even though, in the latter case, it may be operationally interchangeable with natural gas).
2.1,1.5 lean gas
natural gas containing more than 0,15 mole fraction of nitrogen or 0,05 mole fraction of carbon dioxide
NOTE According to ASTM D 4150I4S), a lean gas is a natural gas containing little or no hydrocarbons recoverable as liquid product.
natural gas containing more than 0,10 mole fraction of ethane, or 0,035 mole fraction of propane
NOTE According to ASTM D 4150I(46), a rich gas is a natural gas containing condensable hydrocarbons that can be recovered as liquid product.
18.104.22.168 wet gas
gas which falls short of qualifying as pipeline quality natural gas by the inclusion of undesirable components such as water vapour, free water and/or liquid hydrocarbons, in significantly greater amounts than those quoted for pipeline quality natural gas 1)
22.214.171.124 sour gas
gas failing the qualification as pipeline quality natural gas due to the inclusion of undesirable components such as hydrogen sulphide or carbon dioxide in significantly greater amounts than those quoted for pipeline quality natural gas
NOTE 1 Typically wet and sour gases may be unprocessed (well-head) or partially-processed natural gases and may also contain condensed hydrocarbons, traces of carbonyl sulphide and process fluid vapours such as methanol or glycols.
NOTE 2 According to ASTM D 4150(46), a sour gas is a natural gas containing amounts of sulphur compounds such that it makes it impractical to use, without purification, because of its toxicity or its corrosive effect on piping and equipment. A sweet gas, on the contrary, is a natural gas containing such small amounts of compounds of sulphur that it can be used without purification, with no toxic effects and no deleterious effects on piping and equipment.
NOTE 3 Carbon dioxide in the presence of free water can be an important cause of corrosion damage to pipelines.
1) See also the three notes under 126.96.36.199.
188.8.131.52 dry natural gas
natural gas containing a mole fraction of water of no more than 0,005 % [50 ppm (molar)] in the vapour phase
NOTE Water vapour content in natural gas may be expressed both in terms of water concentration (ppm or mg/m3) and in terms of water dew point. Many relationships can be found in literature correlating water vapour content to dew point. Experimental and theoretical studies on this matter are still being conducted.
The knowledge of water vapour content in natural gas is of particular interest for a safe and efficient transmission and distribution of the gas. Water vapour content in natural gas can be responsible for corrosion phenomena (for example, when in the presence of carbon dioxide, hydrogen sulfide or oxygen) and for hydrate formation. Plugs of liquid water can also hinder transmission operations.
The requirement for gas to be dry may vary significantly depending on the kind of application (transmission, distribution, compressed natural gas for vehicles) and on the location (countries with very cold climates usually have more stringent requirements).
Transmission companies tend to specify very low levels of water content so as to prevent problems which can possibly occur at the high pressures involved. Water content is often specified in terms of water dew point temperature at a defined pressure. These conditions generally correspond to contents ranging from 0,006 % (mole fraction) [60 ppm (molar)] to 0,008 % (mole fraction) [80 ppm (molar)] in water.
At the downstream end of the pipeline, gas is sold to consumers at close to atmospheric pressure, and hence can contain up to about 2 % (mole fraction) of water. Regulations may exist to regulate the cost to the consumer which will depend upon whether the gas is dry or wet under distribution conditions. These regulations will take a very different viewpoint of "wet" and "dry" from those needed for transmission purposes. In the UK, a gas is considered dry if the water content is below about 0,06 % (mole fraction) [600 ppm (molar)] and can be sold by a public gas supplier to the consumer as a gas containing no water. The requirement for distributed gas to be described as dry, where it does exist, may be expected to vary significantly from country to country.
In general practice in the United States, natural gas is considered to be "dry" with a water content of about 0,015 % (mole fraction) [7 lb/106ft3 or about 150 ppm (molar) at standard reference conditions or 0,014% (mole fraction) 140 ppm (molar) at normal reference conditions].
184.108.40.206 high pressure natural gas
natural gas with a pressure exceeding 200 kPa
NOTE In many national standards, high pressure gas is specified at a pressure exceeding 100 kPa. For laboratory use, the value is set at 200 kPa for practical reasons.
220.127.116.11 low pressure natural gas
natural gas having a pressure between 0 kPa and 200 kPa
NOTE These ranges are in accordance with ISO-10715.
18.104.22.168 compressed natural gas
natural gas used as a fuel for vehicles, typically compressed up to 20 000 kPa in the gaseous state
liquefied natural gas
natural gas which has been liquefied, after processing, for storage or transportation purposes
NOTE Liquid natural gas is revaporized and introduced into pipelines for transmission and distribution as natural gas.
22.214.171.124 gas quality
attribute of natural gas defined by its composition and its physical properties
2.1.2 Pipeline network
126.96.36.199 pipeline grid
system of interconnected pipelines, both national and international, which serve to transmit natural gas to local distribution systems
local distribution system
gas mains and services which supply natural gas directly to consumers
location where the natural gas is transferred from the pipeline grid to the local distribution system
188.8.131.52 injection point
location where a supplier of natural gas feeds into the pipeline grid
184.108.40.206 feeding station
system of pipelines, measurement and regulation (pressure control), and ancillary devices at the injection point of the pipeline grid used for the custody transfer of natural gas
220.127.116.11 outlet station
system of pipelines, measurement and regulation (pressure control), and ancillary devices for the delivery of natural gas from the pipeline grid into the local distribution system
NOTE 1 Outlet stations are often called gate stations.
NOTE 2 The custody transfer of natural gas into a pipeline grid and from transmission pipeline grid to local distribution systems requires equipment designed and installed to meet the physical needs of both parties, and to provide for accurate energy measurement to the satisfaction of both.
2.2 Measurement methods
2.2.1 General definitions
measurement of a property from fundamental metrological quantities
NOTE For example, the determination of the mass of a gas using certified masses.
measurement of a property from quantities which, in principle, define the property
NOTE For example, the determination of the calorific value of a gas using the thermometric measurement of the energy released in the form of heat during the combustion of a known amount of gas.
measurement of a property from quantities which, in principle, do not define the property, but have a known relationship with the property
NOTE For example, the determination of the calorific value from measurements of the air-to-gas ratio required to achieve stoichiometric combustion which is related linearly to the calorific value.
measurement of a property from quantities by comparison or interpolation of readings produced by an instrument calibrated using accepted reference materials
NOTE For example, the determination of the calorific value from measurement of the rise in temperature of a heat-exchange fluid caused by the combustion of a gas and calibrated using a substance having a known calorific value. Inferential measurements may be either direct or indirect.
measurement method for direct measurement of properties
method for determining the physical properties of natural gas which does not require a detailed component analysis of the gas
NOTE Such measurements take into consideration the "whole" sample of gas. Some instruments rely upon the absence of certain components for proper operation and may require secondary analytical knowledge to ascertain this absence.
Various measurement methodologies exist, however the distinctions between these categories are not always clear. It is possible for a measurement to belong to more than one category.
measurement of a property by means of comparison or difference from a normal value of the property taken from an accepted reference material
NOTE For example, determining gas density from the quotient of the mass of gas contained in a given volume to that of air contained in the same volume at the same temperature and pressure and multiplying by the density of air at that temperature and pressure.
2.2.2 Specific methods
18.104.22.168 gas chromatographic method
method of analysis by which the components of a gas mixture are separated using gas chromatography
NOTE The sample is passed, in a stream of carrier gas, through a column which has different retention properties relative to the components of interest. Different components pass through the column at different rates and are detected as they elute from the column at different times.
22.214.171.124 potentiometric method
method of analysis by which a known quantity of gas is first passed through a solution, where a specific gas component or a group of components is (are) selectively absorbed, then the absorbed analyte(s) in the solution is(are) evaluated by potentiometric titration
NOTE The result is a titration curve showing the potentiometric end points for the components being sought versus the titration solutions required. From this data, the concentrations of the various components can be calculated.
126.96.36.199 potentiometric titration
method where the reaction of the gas component with the titrant is proportional to its concentration and is measured by the variation of potential inside the cell
NOTE The volume increments of titrant (titration solution) added determine the difference in potential to be measured. Different volume increments of titrant, specifically smaller volume increments close to end points, can permit a better evaluation of the end points.
188.8.131.52 turbidimetric titration
method to determine the content of sulfate ions whereby a barium salt solution is added to an absorption solution and the turbidity caused by the formation of any insoluble barium sulfate detected
NOTE 1 This method is valid for solutions having a total sulfur content below 0,1 mg.
NOTE 2 A photometer with galvanometer readout is employed with the titration procedure to determine the inflection point. From these data, the total sulfur content in mg/m3 can be calculated.
184.108.40.206 combustion method
method by which a gas sample undergoes total combustion and the specific combustion products are measured to determine the total concentration of an element in the sample, e.g. sulfur
NOTE 1 Wickbold method:
The Wickbold combustion method uses the combustion and complete thermal decomposition of compounds at a high temperature in a hydrogen/oxygen flame. It is performed with a special instrument (see ISO 4260I2!).
NOTE 2 Lingener method:
The Lingener combustion method uses air, and it ss performed using a special instrument (see ISO 6326-519)).
extraction of one or more components from a mixture of gases when brought into contact with a liquid
NOTE 1 The assimilation or extraction process causes (or is accompanied by) a physical or chemical change, or both, in the sorbent material.
NOTE 2 The gaseous components are retained by capillary, osmotic, chemical, or solvent action.
EXAMPLE Removal of water from natural gas using glycol.
retention, by physical or chemical forces, of gas molecules, of dissolved substances, or of liquids by the surfaces of solids or liquids with which they are in contact
NOTE For example, retention of methane by carbon.
removal of a sorbed substance by the reverse process of adsorption or absorption
220.127.116.11 aliquot part
part of a whole that is to be analysed
NOTE When analysing an aliquot part, i.e. a part of a whole sample which is homogenous, there is no need to use multiplication to obtain the concentration in the whole sample, because the concentration is the same in the sample and its part.
2.3.1 Sampling methods
sampling in situations where there is a direct connection between the medium to be sampled and the analytical unit (i.e. in-line or on-line instrument)
sampling in situations where there is no direct connection between the medium to be sampled and the analytical unit (i.e. off-line instrument)
NOTE In the case of indirect sampling, depending on the fluctuations of composition and/or properties, the following sampling techniques can be used:
— periodical sampling where a spot sample is periodically taken from the gas stream and brought to the analytical unit;
— incremental sampling which accumulates gas samples into one composite sample then brought to the analytical unit.
instrument whose active element is installed inside the pipeline and makes measurements under pipeline conditions
instrument that samples gas directly from the pipeline, but is installed externally to the pipeline
instrument that has no direct connection to the pipeline
18.104.22.168 spot sample
sample of specified volume taken under operating conditions from a specified place in a gas stream
2) French makes no distinction between "in-line" and "online" installation of the instrument.
2.3.2 Sampling devices
floating piston cylinder
container which has a moving piston separating the sample from a buffer gas
NOTE The pressures are in balance on both sides of the piston.
proportional-flow incremental sampler
sampler that collects gas over a period of time and at a rate that is proportional to the flowrate in the sampled pipeline
22.214.171.124 incremental sampler
sampler that accumulates a series of spot samples into one composite sample
NOTE There are two general classes of commercial incremental samplers:
— pressure increment: a specially designed pressure regulator increases the pressure of the collected sample in a sample cylinder from zero to a maximum of line pressure during the sample period;
— volume increment: the sample is displaced by a pump into a floating piston cylinder at constant line pressure during the sampling period.
container for collecting the gas sample when indirect sampling is necessary
NOTE The sample container should not alter the gas composition in any way or affect the proper collection of the gas sample. The materials, valves, seals, and other components of the sample container should all be specified with this principle.
126.96.36.199 sample line
line provided to transfer a sample of the gas to the sampling point
NOTE It may include devices which are necessary to prepare (he sample for transportation and analysis.
188.8.131.52 sample probe
device inserted into the gas line to be sampled and to which is connected a sample line
NOTE The most elementary sample-probe design is the straight-tube probe. The other type of probe design is the regulated probe. These probes are designed to deliver the gas to the analytical system or sample container at reduced pressure.
184.108.40.206 transfer line
line for carrying the sample to be analysed from the sample point to the analytical unit
220.127.116.11 fast loop
bypass loop that returns to the process line in a closed configuration and used for environmental and safety considerations
NOTE The loop requires a pressure differential from collection point to discharge so as to ensure a constant and steady flowrate through the sampling equipment located in the loop.
18.104.22.168 bypass line
line ultimately vented to the atmosphere that is used where it is impractical to provide a sufficient pressure differential
NOTE The flowrate and pressure loss in the open-ended line need to be controlled so as to ensure that sample accuracy cannot be affected from any cooling and condensation.
2.3.3 Conditioning device
apparatus used to transform the condensable fraction (consisting of water vapour and/or of the higher hydrocarbons) of the vapour phase present in natural gas into a liquid phase by cooling
unit in the gas sample line used to collect liquid fallout
device used to reduce and to control gas pressure entering or moving through a piping system
NOTE It has the ability to maintain a near constant outlet pressure regardless of fluctuations in inlet pressure or flowrate within its design parameters. The regulator can be mechanical or pilot-controlled depending on the application. It operates on the basic principle of the expansion of gas through an orifice against a seat whose positioning is controlled by the downstream pressure acting against a diaphragm linked to the seat.
22.214.171.124 back-pressure regulator
device used to maintain a selected pressure in a system from which gas is being vented to a lower pressure (commonly atmospheric pressure)
NOTE It maintains constant upstream pressure regardless of flowrate or variations in downstream pressure, provided that this does not exceed the selected pressure.
126.96.36.199 heating device
device to ensure that the sample gas remains at, or above, the gas-line temperature, keeping the heavy, end components in the gas phase so as to allow them to be accurately accounted for when the gas is analysed
NOTE Heating elements may be installed on the sample probe and sample lines. In some cases, heating the sample cylinder is also required. It is particularly important where Joule-Thomson cooling occurs as a result of pressure reduction.
2.3.4 Other definitions
188.8.131.52 purging time
time interval necessary to purge a piece of equipment before the gas sample is analysed
184.108.40.206 representative sample
sample having the same composition as the material sampled when the latter is considered totally homogeneous
220.127.116.11 residence time
time interval necessary for a gas sample to flow through a piece of equipment
18.104.22.168 sampling point
location in the gas stream where a sample is obtained
22.214.171.124 gas sorption effects
processes whereby some gases are adsorbed onto or desorbed from the surfaces of a solid
NOTE The force of attraction between some gases and solids is purely physical and depends on the nature of the participating material. Natural gas may contain several components which exhibit strong sorption effects. Special care should be taken when determining trace concentrations of heavy hydrocarbons, water, sultur compounds and hydrogen.
2.4 Analytical systems
complete set of measuring instruments and other equipment assembled to carry out specified measurements
NOTE System comprising, in general, a sample transfer and introduction unit, a separation unit, a detector and an integrator or a data processing system.
2.4.2 introduction unit
unit for introducing a constant, or a measured amount of material to be analysed into the analyser
NOTE 1 Gas chromatographic analysers are comparative rather than absolute. Therefore, the introduction of equal quantities of calibration mixture and of sample allows quantitative measurement of sample components.
NOTE 2 In gas analysis, the introduction device is frequently a multi-port valve, in which a fixed volume of calibration mixture or sample is isolated, and, by operation of the valve, passed into the analyser.
NOTE 3 Equimolar quantities can be obtained by controlling the pressure and temperature of the introduction device.
2.4.3 gas chromatograph
chromatograph that physically separates components of a mixture and measures them individually with a detector whose signal is processed
NOTE 1 A chromatograph consists of the following main parts: an introduction unit, a separation unit and a detector. The separation unit consists of one or more chromatographic columns through which carrier gas flows and into which samples are introduced. Under defined and controlled operating conditions, components can be qualitatively identified by their retention time, and quantitatively measured by comparing their detector response to that of the same or a similar component in a calibration mixture.
NOTE 2 In gas analysis, the range of components and their properties frequently cause more than one separation mechanism to be required. These can be and often are combined in a single separation unit or chromatograph.
NOTE 3 A gas chromatograph capable of temperature programming is a chromatograph whose columns are placed in an oven whose temperature is programmable in a defined and repeatable manner over the period of analysis.
2.4.4 carrier gas
pure gas introduced so as to transport a sample through the separation unit of a gas chromatograph for analytical purposes
NOTE Typical carrier gases are hydrogen, nitrogen, helium and argon.
2.4.5 auxiliary gases
gases required for detector operation, e.g. hydrogen and air for flame detectors
detector that uses a reducing reaction in which molecules give rise to characteristic luminous emissions which are measured by a photomultiplier and the associated electronic devices
NOTE Chemiluminescence detector is used in gas chromatography mainly to detect components which contain particular elements, e.g. nitrogen oxide (NO) and sulphur (S).
detector consisting of an electrochemical cell which responds to certain substances contained in the carrier gas eluting from the column
NOTE The electrochemical process may be an oxidation, reduction or a change in conductivity. The detection can be very specific depending on the electrochemical process involved.
flame ionization detector
detector in which hydrocarbons are burned in a hydrogen-air flame and the resulting ions are measured electrically between two electrodes
NOTE The flame ionization detector is used in gas chromatography mainly to detect hydrocarbon compounds.
thermal conductivity detector TCD
hot wire detector HWD
detector that measures the difference in thermal conductivity between two gas streams when a sample (gas mixture) passes through the sample channel
NOTE 1 The HWD is a dual channel detector, requiring a reference flow of pure carrier gas through the reference channel.
NOTE 2 The use of helium or hydrogen is recommended as carrier gas except when the sample contains either of these two substances to be measured.
NOTE 3 The detector consists of a bridge circuit; the change in resistance in the sample channel during the passage of the sample produces an out-of-balance signal that is the basis of the detection. The detector responds to all components except the carrier gas and it is non-destructive.
flame photometric detector
detector that uses a reducing flame in which individual elements give rise to characteristic colours which are measured by a photomultiplier
NOTE The detector is used in gas chromatography mainly to detect components which contain particular elements, e.g. phosphorous (P) and sulphur (S).
ISO 14532: 2001 (E/F)
device which quantitatively measures the response signal of a detector to a component in a mixture
NOTE By comparing the integrator output to the same component in a calibration mixture and in a sample, the concentration in the sample can be calculated. If the detector response has a time element, as in chromatography. then the instantaneous response is integrated with respect to time.
determination of the concentration of a dissolved substance in a solution by using the absorption of light by this substance
2.4.13 absorption cell
device put into the light path of the photometer
NOTE The lower the concentration of the dissolved substance, the thicker the absorption cell has to be.
accuracy of measurement
closeness of the agreement between a measurement result and a true value of the measurand
NOTE 1 The term accuracy, when applied to a set of measurement results, describes a combination of random components and a common systematic error or bias component.
NOTE 2 Because the true value is seldom known, accuracy often refers to the agreement between measurement results and an accepted reference value.
closeness of agreement between the average value obtained from a large series of measurement results and the true value of the measurand
NOTE The measure of trueness is usually expressed in terms of bias.
systematic difference between the expectation of the measurement results and an accepted reference value
closeness of agreement between independent measurement results obtained under prescribed conditions
NOTE 1 Precision depends only on the distribution of random errors and does not relate to the true value.
NOTE 2 Precision is a qualitative term relating to the dispersion between the results of measurements of the same measurand, carried out under specified conditions of measurement. Quantitative measures of precision such as variance or standard deviation critically depend on the variation implied by the specified measurement conditions.
126.96.36.199 repeatability limit
value below which the absolute difference between two single measurement results obtained using the same method, on identical measurement material, by the same operator, using the same apparatus, in the same laboratory, within a short interval of time, (repeatability conditions), may be expected to lie with a specified probability
NOTE 1 In the absence of other indication the probability is 95 %.
NOTE 2 The rigorous way of calculating the repeatability limit of component measurement, r(xi), is:
is taken from the two-sided t-distribution table at the 5 % significance level with the number of degrees of freedom appropriate to the number of data points from which the standard deviation s(xi) has been calculated; and
188.8.131.52 reproducibility limit
value below which the absolute difference between two single measurement results obtained using the same method, on identical measurement material, by different operators, using different apparatus, in different laboratories, (reproducibility conditions), may be expected to lie with a specified probability
NOTE In the absence of other indication the probability is 95 %.
estimate attached to a measurement result which characterizes the range of values within which the true value is asserted to lie
NOTE 1 Uncertainty of measurements comprises, in general, many components. Some of these components may be estimated on the basis of the statistical distribution of the results of a series of measurements and can be characterized by experimental standard deviation. Estimates of other components can only be based on experience or other information.
NOTE 2 Uncertainty should be distinguished from an estimate attached to a measurement result which characterizes the range of values within which the expectation is asserted to lie. This latter estimate is a measure of precision rather than of accuracy and should be used only when the true value is not defined. When the expectation is used instead of the true value the expression "random component of uncertainty" should be used.
NOTE 3 Since the terminology relating to accuracy and/or uncertainty of measurement has recently undergone substantial changes, a short comment on the meaning of the main terms shall be given.
Accuracy, trueness and precision are qualitative terms used to express the smallness of expected measurement errors. Hereby accuracy as the more general term refers to the total measurement error, trueness to the systematic components), and precision to the random component (s) of measurement error.
Uncertainty, systematic uncertainty and random uncertainty (dispersion) are qualitative terms used to express the extent of expected measurement errors, as the counterparts of accuracy, trueness, and precision, respectively. Accuracy and uncertainty are reciprocal terms: high accuracy is equivalent to small uncertainty, and the same is true for both the other pairs of reciprocal terms, i.e. trueness with systematic uncertainty and precision with random uncertainty (dispersion).
For quantitative expressions of accuracy or uncertainty the common measures, derived from the results of repeated measurements, are:
— bias for systematic uncertainty; and
— standard deviation for random uncertainty (dispersion).
2.5.2 Calibration and quality control
device intended to reproduce or supply, in a permanent manner during its use, one or more known values of a given quantity
NOTE The quantity concerned may be called the supplied quantity.
set of operations that establish, under specified conditions, the relationship between values of quantities indicated by a measuring instrument or measuring system, or values represented by a material measure or a reference material, and the corresponding values obtained using working standards
NOTE 1 Adapted from the VIM.
NOTE 2 The result of a calibration permits either the assignment of values of measurements to the indicated reading or the determination of the corrections with respect to indicated readings.
NOTE 3 A calibration may also determine other metrological properties that affect the result of the measurement, i.e. influence quantities.
NOTE 4 The result of a calibration may be reported in a document, sometimes called a calibration certificate or a calibration report.
NOTE 5 The measuring instrument can be calibrated over its entire working range or simply in a specific portion of its range.
NOTE 6 A laboratory which performs calibrations can be accredited for this activity. In order to assess the traceability of the calibrations reported, protocols covering the relevant uncertainty analysis and other quality assurance elements are required.
NOTE 7 Calibration includes the adjustment and/or correction of instruments giving readings during calibration that are outside acceptable limits.
184.108.40.206 calibration interval
period of time during which the analytical system would normally be used between calibrations
220.127.116.11 single-point calibration
establishment of the calibration function using one (only) calibration point, below which the estimated value of the property is expected to lie
NOTE 1 Notes 2, 3 and 4 are applicable to analytical systems,
NOTE 2 This is a calibration in which the response of the analyser to a measured component maintains an exact proportion to the concentration of the component over the entire working range.
NOTE 3 The response can be described as being linear through the origin. A plot of the analyser response against the concentration of the component would show a straight line intercepting the (0, 0) point of the plot. In such circumstances, the use of a single calibration mixture containing the component at a concentration within the working range (single-point calibration) is appropriate, as the ratio of response to concentration remains constant at all points.
NOTE 4 Where a more complex response function, such as a second or third order polynomial, has been defined by the use of multiple calibration mixtures, and the different elements of this function, e.g. the coefficient of the polynomial, have been shown to maintain a constant relationship to each other, then a single-point calibration can be used to adjust all the elements of the function on a short term basis (for example, daily).
method consisting in principle in reducing the interval over which the linearity of the calibration function is assumed as much as possible
NOTE This leads to surrounding the value of the unknown quantity by two values of reference materials (RMs) as tightly as possible (or bracketing).
establishment of a calibration function using several (more than two) calibration points which define a range within which the estimated values of the properties are expected to lie
NOTE 1 Notes 2 and 3 are applicable to analytical systems.
NOTE 2 In multi-point (also called "multi-level") calibrations, the response curves of the detector are determined for each component over the ranges to be analysed.
NOTE 3 To define the response curves, it is necessary to obtain results at a number of different concentration levels for each component. The number of concentration levels needed depends on the order of the polynomial (response curve) that has to be fitted. The minimum number of concentration levels needed is the same as the number of polynomial coefficients in the response curve to be fitted. However, it is advisable to analyse a few extra concentration levels than strictly necessary. In most cases, the order of fit of the response curves is unknown beforehand. Therefore a few extra points for fitting the response curve will decrease the influence of the measurement errors made during calibration. Consequently, it is advisable to perform the analysis of at least seven concentration levels so as to detect third order detector behaviour with a high degree of detection sensitivity.
The concentration levels shall correspond to at least seven different certified reference gas mixtures.
These concentration levels should be equally spaced across the specified working range of each component. The lowest concentration level should be slightly below the lowest concentration level of the working range, the highest concentration level should be slightly higher than the highest concentration level of the working range.
correction of future measurements if both the accepted values of the RMs and the observed values have the same units or a translation from the units of the observed measurements to the units of the RMs
process to specify procedures and equipment for limited tests performed over a restricted range with traceable materials or instruments on a regular basis or upon indication of need in order to detect whether the system is behaving normally or erratically with no adjustment or correction of the measurement system
control method control chart
method which monitors the measurement system on a regular basis so as to detect quickly when the method has deteriorated, or the calibration shifted, or both
NOTE 1 Detection is achieved by using control charts for each component. A control gas of known composition, typical of the natural gases for which the method is to be used, is required (or the preparation of a control chart.
Before the first use, the control gas is analysed at least 10 times for precision data to be calculated (mean concentration and standard deviation for each component in the test gas).
For each component in the control gas, a control chart is constructed with the mean value for the component and concentrations representing the mean ± 2 standard deviations and the mean ± 3 standard deviations marked on the y-axis. Lines parallel to the x-axis are drawn from these points. Each time the control gas is analysed, the value is plotted using the x-axis as a time scale.
The plotted values from each analysis of the control gas are compared with the mean value and the lines for ± 2 standard deviations and ± 3 standard deviations.
Assuming that the composition of the control gas is stable and that the analytical results for the control gas follow a normal distribution, then for a system behaving normally, it may be expected that any individual result for the control gas can possibly fall outside the limit of ± 2 standard deviations on 1 occasion in 20. This means that if individual results fall outside the warning limits (± 2 standard deviations) more frequently than this, it can be an indication that the system is steering out of control with a systematic tendency for results to be too high (or too low) or the random error for measurement of that component to increase.
NOTE 2 This control method can be applied to various other instruments apart from an analyser.
2.5.3 Gas analysis
18.104.22.168.1 mass [volume] [mole] fraction
quotient of the mass [volume (under specified conditions of pressure and temperature)] [number of moles] of each component to the sum of the masses [sum of the volumes (intended prior to mixing under specified conditions of pressure and temperature)] [sum of the moles] of all components of the gas mixture
NOTE According to ISO 7504, the sum of the volumes of all components of the gas mixture prior to mixing is replaced by the volume of the gas mixture.
For a real gas, the sum of the volumes of all components of the gas mixture does not give in general the volume of the mixture since mixing of different components generally results in changes of intermolecular forces which in turn cause an increase or decrease of total volume. The sum of the masses or numbers of moles of all components of the gas mixture gives the mass or number of moles of the mixture.
For an ideal gas, the mole fraction is identical to the volume fraction, but this relationship cannot, in general, be assumed to apply to real gas behaviour for the reason mentioned above.
The mass and mole fractions are independent of pressure and temperature of the gas mixture. The volume fraction depends on pressure and temperature of the gas mixture.
The percentage is calculated from the fraction multiplied by 100.
22.214.171.124.2 mass [molar] concentration
quotient of the mass [number of moles] of each component to the volume of the gas mixture under specified conditions of pressure and temperature
NOTE The mass and molar concentrations depend on the pressure and temperature of the gas mixture.
amount of substance of any chemical species which contains the relative molecular mass
NOTE A table of recommended values of relative molecular masses is given in ISO 6976.
fractions or percentages of the main components, associated components, trace components and other components determined from natural gas analysis
126.96.36.199.5 gas analysis
test methods and techniques for determining the gas composition
direct chromatographic measurement of components
individual components or groups of components determined by comparison with identical components in the working reference gas mixture (WRM)
NOTE Main and associated components are determined using direct measurement.
188.8.131.52.7 indirect chromatographic measurement of components
individual components or groups of components determined using relative response factors to a reference component in the WRM
NOTE Trace components are determined using indirect measurement.
184.108.40.206 Analysed components
component whose content influences the calculation of physical properties
NOTE Main components of natural gases generally include: nitrogen, carbon dioxide and saturated hydrocarbons from methane through n-pentane.
component whose content does not significantly influence the calculation of physical properties
NOTE Associated components generally include: helium, hydrogen, argon and oxygen.
component present at very low levels
NOTE Trace components generally include hydrocarbons or groups of hydrocarbons above n-pentane and the components listed in 220.127.116.11.
group of components
individual components whose similar properties make analytical separation too poor for individual determination and are thus considered and treated as a group of components in the mixture
NOTE 1 The property of the group, rather than each individual property, is used to evaluate the properties of the mixture.
NOTE 2 The group may be physically combined as a result of the analytical procedure, as with backflushing in chromatography, or individually measured and combined by calculation. If they are physically combined, the precision of
the measurement of the group is likely to be superior to the precision of measurement of the individual components.
NOTE 3 It is important to recognize when it is appropriate to consider groups of components, and when it is not. For calculation of calorific value or relative density, all hydrocarbons of carbon number six (C6) and higher can be considered as a group (C6+) with relatively little resulting error. However, such simplification gives rise to large calculation errors of the hydrocarbon dew point.
NOTE 4 When a number of hydrocarbons are identified and quantified as a group or groups, the following options are possible:
— the total is reported as though the group extends from the lowest carbon number of that group (e.g. C6+, which indicates all hydrocarbons of carbon number six and above);
— separate groups are reported as the total of each carbon number (e.g. total C6, total C7, etc.);
— the above groups, reported as total of each carbon number, can be further broken down to component types (e.g. C6 alkanes, as distinct from benzene and C6 cycloalkanes or naphthenes).
In the above mentioned cases, the response of the group is the sum of the responses of the normal hydrocarbon components) and its (their) isomers. The relative response of the group is equal to the relative response of the normal alkane of the group (C6 for C6+).
component possibly being present in the gas, which is either measured directly using other analytical methods or its content in the gas is assumed to remain constant and set to a value based on past measurements or valid estimations
component present in the WRM used as a reference to define the relative response factors of sample components which are not present in the WRM
NOTE The response function of the reference component and of the sample components measured relative to it should be linear and pass through the origin.
18.104.22.168 Trace component [constituent]
22.214.171.124.1 alkane thiol
organic sulfur compound with the general formula R-SH (where R is the alkyl group), either naturally present or added as an odorant to natural gas
NOTE 1 They are classified as primary, secondary and tertiary thiols (mercaptans) according to whether the a!kyl group attached to the thiol (mercaptan) group is a primary, secondary or tertiary group, respectively. The number o( carbons attached to the carbon atom bearing the thiol group distinguishes primary, secondary and tertiary thiols.
In a primary alkyi group, one or none carbon is attached to the carbon atom under consideration. [Examples of primary thiols (mercaptans): methane thiol (methyl mercaptan) CH3-SH, ethane thiol (ethyl mercaptan) CH3CH2-SH].
In a secondary alkyi group, two carbons are attached to the carbon atom under consideration. (Example of a secondary thiol (mercaptan): 2-propane-thiol (isopropyl mercaptan) (CH3)2CH-SH).
In a tertiary alkyi group, three carbons are attached to the carbon atom under consideration. (Example of a tertiary thiol (mercaptan): 2-methylpropane-2-thiol (tertiary-butyl mercaptan) (CH3)3C-SH).
NOTE 2 Thiols (mercaptans) are the sulfur analogues of the alcohols.
126.96.36.199.2 alkyi sulfide
organic sulfur compound with the general formula R-S-R' (where R and R' are alkyi groups), either naturally present or added as an odorant to natural gas
NOTE 1 The alkyi groups are identical (R = R') in symmetrical sulfides (e.g. diethyl sulfide: C2H5-S-C2H5) or different (R =/ R'), in asymmetrical sulfides (e.g. methyl ethyl sulfide: CH3-S-C2H5).
NOTE 2 Sulfides are the sulfur analogues of the ethers and are also known as thioethers.
188.8.131.52.3 alkyi disulfide
organic sulfur compound with the general formula R-S-S-R' (where R and R' are alkyi groups)
NOTE 1 The alkyi groups are identical (R = R') in symmetrical disulfides (e.g. dimethyl disulfide:
CH3-S-S-CH3) or different (R =/ R') in asymmetrical disulfides (e.g. methyl ethyl disulfide: CH3-S-S-C2H5).
NOTE 2 Disulfides are formed by oxidation of thiols (mercaptans). Their odour intensity is insufficient to be used as gas odorants.
184.108.40.206.4 carbonyl sulfide
sulfur compound found in natural gas, which contributes to the total sulfur content
NOTE Under particular conditions, it can be formed from, or be converted to, H2S.
carbonyl sulfide sulfur
amount of sulfur in natural gas found in the form of carbonyl sulfide (COS) and determined, for example, by potentiometry (ISO 6326-3)
220.127.116.11.6 cyclic sulfide
cyclic organic sulfur compound with one sulfur atom incorporated into a saturated hydrocarbon ring
EXAMPLE Tetrahydrothiophene (thiophane or thiacyclopentane), i.e. C4H8S, which is added as an odorant to natural gas.
liquid binary alcohol (R-CHOH-CH2OH) used as an anti-freeze and in some processing operations as a dehydrating agent
colourless, toxic gas with an odour similar to rotten eggs
NOTE H2S is an undesirable constituent of natural gas, and should be reduced to tolerable concentrations by processing. A low concentration of hydrogen sulfide provides safety for personnel and customer, mitigates corrosion in pipeline and distribution systems, prevents objectionable products, of combustion, and protects sensitive industrial operations.
ISO 14532:2001 (E/F)
see alkane thiol (18.104.22.168.1) [(alkyl mercaptan)
22.214.171.124.10 mercaptan sulfur
see thiol sulfur (126.96.36.199.15)
light, volatile, flammable, poisonous, liquid alcohol (CH3OH) used to prevent hydrate formation in wet, high-pressure gas lines
188.8.131.52.12 organic sulfur
term commonly used to designate all of the sulfur compounds in natural gas with the exception of hydrogen sulfide and sulfur oxides
EXAMPLES These sulfur compounds consist of carbon disulfide (CS2), carbon oxysulfide, also called carbonyl sulfide (COS), thiophene (C4H4S) and its homologues, alkane thiols (alkyi mercaptans) such as methane thiol (methyl mercaptan) (CH3-SH) and ethane thiol (ethyl mercaptan) (C2H5-SH), and various other sulfur compounds present in very small traces, such as the thioethers and the alkyi disulfides.
see alkyl or cyclic sulfide (184.108.40.206.6)
see sulfide (220.127.116.11.13)
thiol [mercaptan] sulfur
amount of sulfur bonded in the form of a thiol [mercaptan] in natural gas
NOTE The amount of thiol sulfur may be determined by an analytical method which does not differentiate between individual thiols [mercaptans] (e.g. potentiometry using ISO 6326-3171).
see alkane thiol (18.104.22.168.1) [(alkyi mercaptan) (22.214.171.124.1)]
total amount of sulfur found in natural gas
NOTE The total amount of sulfur, both organic and inorganic, may be determined by an analytical method not differentiating between individual sulfur compounds [e.g. Wickbold (ISO 4260(21) or Lingener (ISO 6326-5191) combustion methods].
126.96.36.199 Analyser response
output signal for a component that is measured as peak area or peak height
NOTE Response is expressed in counts.
188.8.131.52.2 response factor
ratio of the non-normalized mole fraction of the component in the WRM to its response
NOTE 1 The response factor for this component is defined on the assumption that the detector behaviour for a certain component intercepts the origin and is linear for a small range around the point which is calibrated; in this case, a single-point calibration is used.
NOTE 2 In this case the non-normalized mole fraction of this component in the sample is given by the product of the response factor of this component with the response of the same component in the sample:
is the non-normalized mole fraction for component i in the sample;
is the non-normalized mole fraction for component i in the WRM;
is the response factor, expressed in counts, for component; in the sample;
is the response factor, expressed in counts, for component i in the WRM.
184.108.40.206.3 relative response factor
ratio of the molar amount of the component analysed to the molar amount of reference component present in the working reference gas mixture (WRM) which produces an equal response from the analyser
NOTE 1 It is necessary to use the relative response (actor to calculate the non-normalized mole fraction of sample components not present in the WRM.
NOTE 2 The relative response factor for a certain component can also be defined as the ratio of the response factor of this component to the response factor of the reference component.
NOTE 3 When using an FID detector, the relative response factor is calculated as the ratio of the carbon number of the reference component to the carbon number of the sample component.
NOTE 4 It is assumed that the detector response curve, calibrated using the reference component, intercepts the origin and is linear for a small range around the point obtained for the sample component. The non-normalized mole fraction of the sample component not present in the WRM can be calculated by the following equation:
is the non-normalized mole fraction for component i in the sample which is not present in the WRM;
is the non-normalized mole fraction for the reference component in the WRM;
is the response factor, expressed in counts, for component i in the sample;
is the response factor, expressed in counts, for component for the reference component in the WRM;
the relative response factor (or the reference component with respect to component;'.
220.127.116.11.4 response function
response of the detector after a multi-point calibration performed for a component over the range to be analysed (see the note in the definition of the multi-point calibration in 18.104.22.168)
NOTE 1 It is not possible to make the assumption that the detector response function calibrated for a certain component intercepts the origin and is linear for a small range around the measured point.
NOTE 2 In this case, the non-normalized mole traction of the component in the sample is given by the product of the response function of the component in the sample with the scaling factor:
is the non-normalized mole fraction for component i in the sample;
is the mole fraction for component i in the WRM;
is the response factor, expressed in counts, for component i in the sample;
is the response factor, expressed in counts, for component i in the WRM;
a, b, c, d are the polynomial coefficients.
composition data is set to 100 % or to some slightly lesser value if there is a small, constant and recognized contribution from unmeasured other components
NOTE 1 Analysers which have been set up for natural gas analysis, however well configured, will rarely measure the sum of the components in a natural gas to be exactly 100 % (or 1 if expressed in mole fraction). Therefore composition data is normalized to 100 %.
This is based on the obvious premise that the sum of all components in a natural gas adds up to 100% and not some other value:
xmc is the mole fraction for main and associated components;
xtc is the mole fraction for trace components;
xoc is the mole fraction for other components;
The normalization is carried out as follows:
xOC is the non-normalized mole fraction for component i in the sample;
xi,S is the normalized mole fraction for component i in the sample;
xOC,S is the normalized mole fraction for sum of the other components in the sample;
k is the number of components detected.
NOTE 2 The method should quote limits within which such normalization would be acceptable; a measured total between 0,99 and 1,01 may be deemed to be usual, with analyses producing wider-ranging totals being rejected. Analytical methods which calculate the methane by difference do not normalize in this way, but instead force the total to 1, with the calculated methane value absorbing the errors in all the other component measurements.
22.214.171.124.6 chromatographic resolution
column efficiency characteristic describing the degree of separation of two adjacent peaks in gas chromatography
NOTE The resolution is measured for two eluted components, A and B. as twice the difference of their retention times, measured at their maxima, divided by the sum of the peak widths measured at their baseline. The peak width is measured by drawing tangents to the peaks at half their height and measuring the distance between the intercepts of these two tangent lines at the baseline:
RA,B is the resolution between peaks for components A and B;
tR(A), tR(B) retention time of the eluted components A and B;
w(A), w(B) peak widths at the baseline of the eluted components A and B measured with respect to retention time.
In the case where the retention time scale of the chromatogram is linear, chromatogram distances can be measured instead of retention times.
126.96.36.199 Calibration gas mixtures
188.8.131.52.1 General definitions from metrology
184.108.40.206.1.1 reference material
material or substance, one or more of whose property values are sufficiently homogeneous and well established to be used for the calibration of an apparatus, the assessment of a measurement method, or for assigning values to materials
[ISO Guide 30]
NOTE A reference material may be in the form of a pure or mixed gas, liquid or solid.
EXAMPLES Several kinds of reference materials exist. An internal reference material is an RM developed by a user for its own internal use. An external reference material is an RM provided by someone other than the user. A certified reference material (CRM) is an RM issued and certified by an organization recognized as competent to do so.
certified reference material
reference material, accompanied by a certificate, one or more of whose property values are certified by a procedure which establishes traceability to an accurate realization of the unit in which the property values are expressed, and for which each certified value is accompanied by an uncertainty at a stated level of confidence
[ISO Guide 30]
reference measuring system
represents not only a measuring instrument but the set of procedures, operators and environmental conditions associated with that instrument
property of the result of a measurement or the value of a standard whereby it can be related to stated references, usually national or International Standards, through an unbroken chain of comparisons all having stated uncertainties
[ISO Guide 30]
NOTE 1 The concept is often expressed by the adjective traceable.
NOTE 2 It should be noted that traceability only exists when scientifically rigorous evidence is collected on a continuing basis showing that the measurement is producing documented results for which the total measurement uncertainty is quantified (NIST Technical Note 1297:1994 Edition).
NOTE 3 The unbroken chain of comparisons is called a traceability chain.
measurement standard etalon
material measure, measuring instrument, reference material or measuring system intended to define, realize, conserve or reproduce a unit of one or more values of a quantity to serve as a reference
220.127.116.11.1.6 group standard series of standards
set of standards of specially chosen values which individually or in suitable combination reproduce a series of values of a quantity over a given range
NOTE Adapted from the VIM.
18.104.22.168.1.7 primary standard
standard that is designated or widely acknowledged as having the highest metrological qualities and whose value is accepted without reference to other standards of the same quantity
NOTE 1 The concept of primary standard is equally valid for base quantities and derived quantities.
NOTE 2 A primary standard is never used directly for measurements other than for comparison with duplicate or reference standards. In general the National Standards
Laboratory is responsible for the conservation of a primary standard in a country.
22.214.171.124.1.8 secondary standard
standard whose value is assigned by comparison with a primary standard of the same quantity
international measurement standard
standard recognized by an international agreement to serve internationally as the basis for assigning values to other standards of the quantity concerned
126.96.36.199.1.10 national measurement standard
standard recognized by a national decision to serve, in a country, as the basis for assigning values to other standards of the quantity concerned
NOTE A. National Standards Laboratory assures that the national standards are primary standards.
188.8.131.52.1.11 reference standard
standard generally having the highest metrological quality available at a given location or in a given organization, from which measurements made there are derived
184.108.40.206.1.12 working standard
standard that is used routinely to calibrate or check material measures, measuring instruments or reference materials
NOTE A working standard is usually calibrated against a reference standard.
220.127.116.11.1.13 transfer standard
standard used as an intermediary to compare standards
18.104.22.168.2 Definitions relevant to gas mixtures
primary standard gas mixture
gas mixture whose component quantity levels have been determined with the utmost accuracy and can be used as a reference gas for determining the component quantity levels of other gas mixtures
secondary standard gas mixture
gas mixture whose component quantity levels have been validated by direct comparison with a PSM
NOTE A secondary standard gas mixture is a CRM. It is used for the determination of the response curves of the measuring system and can also be used for its regular calibration. It can be a binary or multi-component mixture and can be prepared gravimetrically in accordance with IS06142I3) and verified in accordance with IS06143!4]. The quantity levels of the components can be determined by comparison with a PSM of closely related composition in accordance with ISO 61431.
working reference gas mixture
gas mixture whose component quantity levels have been validated by direct comparison with a secondary standard gas mixture
NOTE A WRM is used regularly to calibrate the measuring system. A WRM can be a binary or a multi-component mixture and can be prepared gravimetrically in accordance with IS06142 and verified in accordance with ISO 6143. The quantity levels of the components can be determined by comparison with a CRM of closely related composition in accordance with ISO 6143.
22.214.171.124.2.4 control gas
gas mixture of known composition containing all the components present in the working reference gas mixture
NOTE A control gas can be either a sample gas with a composition determined in accordance with ISO 6143I4! or a multi-component mixture prepared in accordance with ISO 6142. A control gas is used to calculate the mean (µ) and standard deviation (σ) of the quantity levels of the components detected so as to prepare the relevant control charts.
126.96.36.199 sequential F-test
statistical test used sequentially to compare the goodness of fit to data of two polynomial curves of different order varying from third order (the highest order of interest) to possibly first order so as to determine the curve that best fits the data
NOTE 1 If the third order polynomial fits the data, it is accepted. If not, the second order is similarly compared with a first order and, if necessary, the first order is compared with the first order through the origin.
NOTE 2 The sequential f-test can be used for fitting a polynomial to the data. After calculating the four possible response curves of interest for a component (first order polynomial through the origin, first, second or third order polynomials), it is necessary to choose the most appropriate curve. This decision can be based on the use of a sequential F-test.
188.8.131.52 critical value
tabulated value from a particular table against which a measured statistic is compared
NOTE The tables cover the t- and F-distributions and data for Grubbs' and Cochran's tests. The critical value is read from the table at the chosen level of probability, and at the degree or degrees of freedom equivalent to the parameters involved in the test. In some cases, more than one critical value may be required, and the test statistic compared with, for example, both 95 % and 99 % levels.
extreme value of the measured values which exceeds the tabulated value at the chosen significance level
extreme value of the measured value which exceeds the tabulated value at the 5 % significance level
2.6 Physical and chemical properties
2.6.1 Reference conditions
184.108.40.206 combustion reference conditions
specified conditions of pressure and temperature at which natural gas is notionally (see note) burned
NOTE "Notionally" has the meaning in this context of speculative or imaginary. Since ISO 6976 refers to calculation of calorific value from composition, the metering and combustion temperatures refer to those which would exist if combustion calorimeter had been used instead.
220.127.116.11 metering reference conditions
specified conditions of pressure and temperature at which the amount of natural gas to be burned is notionally (see note in 18.104.22.168) determined
NOTE 1 There is no a priori reason for these conditions to be the same as the combustion reference conditions.
NOTE 2 See ISO 6976.
normal reference conditions
reference conditions of pressure, temperature and humidity (state of saturation) equal to: 101,325kPa and 273,15 K for a dry, real gas
standard reference conditions
reference conditions of pressure, temperature and humidity (state of saturation) equal to: 101,325kPa and 288,15 K for a dry, real gas
NOTE 1 Good practice requires that the reference conditions be incorporated as part of the symbol, and not of the unit, for the physical quantity represented.
is the superior calorific value on volumetric basis;
pcrc is the pressure of the combustion reference conditions;
Tcrc 7- is the temperature of the combustion reference conditions;
V(pmrc, Tmrc)is the volume at the temperature and the pressure of the metering reference
NOTE 2 Standard reference conditions are also referred to as metric standard conditions.
NOTE 3 The abbreviation s.t.p. (standard temperature and pressure) replaces the abbreviation N.T.P. (Normal Temperature and Pressure), as formerly used, and is defined as the condition of pressure and temperature equal to: 101,325 kPa and 288,15 K. No restriction is given on the state of saturation.
2.6.2 Behaviour of ideal and real gas
22.214.171.124 ideal gas
gas that obeys the ideal gas law
NOTE 1 The idea! gas law is given by:
p is the absolute pressure;
Vm is the molar volume;
R is the molar gas constant;
T is the thermodynamic temperature.
NOTE 2 No real gas obeys this law; for real gases the above equation should be rewritten as:
Z(p, T) is the compression factor.
gas compressibility factor
quotient of the actual (real) volume of an arbitrary mass of gas, at a specified pressure and temperature, and the volume of the same gas, under the same conditions, as calculated from the ideal gas law
NOTE 1 The formula for the compression factor is as follows:
p is the absolute pressure;
T is the thermodynamic temperature;
y is the set of parameters which uniquely characterizes the gas;
Vm is the molar volume;
R is the molar gas constant;
Z is the compression factor.
In principle, v may be the complete molar composition (see ISO 12213-2) or a distinctive set of dependent physicochemical properties (see ISO 12213-3).
NOTE 2 The compression factor is a dimensionless quantity usually close to unity near standard or normal reference conditions. Within the range of pressures and temperatures encountered in gas transmission, the compression factor can significantly differ from unity.
NOTE 3 The supercompressibility factor, f, is defined as the square root of the ratio of the compression factor at reference conditions to the compression factor of the same gas at the conditions of interest:
where Zb is the compression factor at base conditions of pressure and temperature.
Base conditions are temperature and pressure conditions at which natural gas volumes are determined for the purpose of custody transfer. In natural gas measurements the properties of interest are temperature, pressure and composition. Assuming ideal gas properties, for simplicity, tables of pure compounds can be prepared for use in calculating gas properties for any composition at "base conditions". These "base conditions" are chosen near ambient.
In the IGU Dictionary of the Gas Industry the supercompressibility factor is defined as:
The supercompressibility factor is used with measurements made by flow instruments. The volume obtained with a flowmeter should be multiplied by ”f” to obtain the corrected volume.
The compression factor is used with measurements made by displacement methods. In this case the volume should be multiplied by “1/Z” to obtain the correct volume.
mass of gas divided by its volume at specified conditions of pressure and temperature
NOTE In a mathematical representation the density is given by:
126.96.36.199 relative density
quotient of the mass of a gas, contained within an arbitrary volume, and the mass of dry air of standard composition (defined in ISO 69761221) which would be contained in the same volume at the same reference conditions
NOTE 1 An equivalent definition is given by the ratio of the density of the gas pg to the density of dry air of standard composition pa at the same reference conditions.
d is the relative density;
psrc is the pressure at standard reference conditions;
Tsrc is the temperature at standard reference conditions;
ρ(psrc, Tsrc) js the density at the standard reference conditions of temperature and the pressure.
NOTE 2 Density can be expressed in terms of the real gas law;
With this relation the relative density, when both gas and air are considered as real fluids, becomes:
For ideal gas behaviour of the gases, when both gas and air are considered as fluids which obey the ideal gas law, the relative density becomes:
NOTE 3 In former times, the above ratio MglMa was called the specific gravity of a gas, which has the same value as the relative density if ideal behaviour of the gases is assumed. The term relative density should now replace the term specific gravity.
2.6.4 Combustion properties
188.8.131.52 superior calorific value
energy released as heat by the complete combustion in air of a specified quantity of gas, in such a way that the pressure p1 at which the reaction takes place remains constant, and all the products of combustion are returned to the same specified temperature T1 as that of the reactants, all of these products being in the gaseous state except for water formed by combustion, which is condensed to the liquid state at T1
NOTE 1 Where the quantity of gas is specified on a molar basis, the calorific value, expressed in MJ/mol, is designated as:
On a mass basis the calorific value, expressed in MJ/kg, is designated as:
Where the quantity of gas is specified on a volumetric basis, the calorific value, expressed in MJ/m3 is designated as:
where T2, and p2 are the gas volume (metering) reference conditions.
NOTE 2 The terms gross, higher, upper and total calorific value, or heating value, are synonymous with superior calorific value.
184.108.40.206 inferior calorific value
energy released as heat by the complete combustion in air of a specified quantity of gas, in such a way that the pressure pi at which the reaction takes place remains constant, and all the products of combustion are returned to the same specified temperature Ti as that of the reactants, all of these products being in the gaseous state
NOTE 1 Superior calorific value differs from inferior calorific value by the heat of condensation of water formed by combustion.
NOTE 2 Where the quantity of gas is specified on a molar basis, the calorific value, expressed in MJ/mol, is designated as:
On a mass basis the calorific value, expressed in MJ/kg, is designated as:
Where the quantity of gas is specified on a volumetric basis, the calorific value, expressed in MJ/m3, is designated as:
where T2 and p2 are the gas volume (metering) reference conditions.
NOTE 3 The terms net and lower calorific value, or heating value, are synonymous with inferior calorific value.
NOTE 4 Superior and inferior calorific values can also be stated as dry or wet (denoted by the subscript "w") depending on the water vapour content of the gas prior to combustion.
The effects of water vapour on the calorific values, either directly measurer or calculated, are described in annex F of ISO 6976:1995
NOTE 5 Normally the calorific value is expressed as the superior, dry value specified on a volumetric basis under standard reference conditions.
enthalpy of transition
enthalpy of transformation
amount of heat released accompanying the transition of a substance from one state to another
NOTE By convention, positive heat release is numerically equal to an increment of negative enthalpy (for a heat-releasing transition, ΔH<0). The quantities, enthalpy of combustion and enthalpy of vaporization, should have meanings that are evident. The term enthalpic correction refers to the (molar) difference in enthalpy for the transition of a gas from an ideal state to a real state.
calorific value, on a volumetric basis, at specified reference conditions, divided by the square root of the relative density at the same specified metering reference conditions
NOTE 1 The Wobbe index is specified as superior (denoted by the subscript "S") or inferior (denoted by the subscript "I"), depending on the calorific value, and as dry or wet (denoted by the subscript "w") depending on the calorific value and the corresponding density.
NOTE 2 The Wobbe index is a measure of heat input to gas appliances derived from the orifice flow equation. Heat input for different natural gas compositions is the same if they have the same Wobbe index, and operate under the same gas pressure (see ISO 6976(221).
2.6.5 Dew points
220.127.116.11 Water dew point
18.104.22.168.1 water dew point
temperature above which no condensation of water occurs at a specified pressure
NOTE For any pressure lower than the specified pressure there is no condensation at this dew point temperature.
22.214.171.124.2 water content
mass concentration of the total amount of water contained in a gas
NOTE 1 Water content is expressed in grams per cubic metre.
NOTE 2 For raw gas, this means water in the forms of both liquid and vapour, but for pipeline gas this means only water vapour.
126.96.36.199 Hydrocarbon dew point
188.8.131.52.1 hydrocarbon dew point
temperature above which no condensation of hydrocarbons occurs at a specified pressure
NOTE 1 At a given dew point temperature there is a pressure range within which retrograde condensation can occur. The cricondentherm defines the maximum temperature at which this condensation can occur.
NOTE 2 The dew point line is the locus of points for pressure and temperature which separates the single phase gas from the biphasic gas-liquid region.
184.108.40.206.2 retrograde condensation
phenomenon associated with the non-ideal behaviour of a hydrocarbon mixture in the critical region wherein, at constant temperature, the vapour phase in contact with the liquid may be condensed by a decrease in pressure; or at constant pressure, the vapour is condensed by an increase in temperature
NOTE Retrograde condensation of natural gas is the formation of liquid when gas is heated or pressure is reduced.
220.127.116.11.3 potential hydrocarbon liquid content
amount of liquid potentially condensable per unit volume of gas at a given temperature and pressure
2.6.6 Other definitions
18.104.22.168 methane number
rating indicating the knocking characteristics of a fuel gas
NOTE It is comparable to the octane number for petrol. The methane number expresses the volume percentage of methane in a methane-hydrogen mixture which, in a test engine under standard conditions, has the same tendency to knock as the fuel gas to be examined.
ISO 14532:2001 (E/F)
measure of the degree to which combustion characteristics of one gas are compatible with those of another gas
NOTE Two gases are said to be interchangeable when one gas may be substituted for the other gas without interfering with the operation of gas-burning appliances or equipment.
family of gases
set of gases having common main constituents
group of gases
subset of a family of gases, categorized as having similar combustion characteristics with reference to limit gases and test pressures
2.7.4 reference gas
gas with which appliances operate under nominal conditions when supplied at the corresponding normal pressure
NOTE Nominal conditions are the conditions at which appliances have been optimized to give their best performance.
2.7.5 limit gas
gas representative of one of the extreme variations, in terms of the Wobbe Index, categorizing a group of gases
pressure at which appliances operate under nominal conditions when they are supplied with the corresponding reference gas
NOTE Nominal conditions are the conditions at which appliances have been optimized to give their best performance.
pressure representative of a possible extreme pressure variation resulting from gas supply conditions of the appliance
tendency for the flame to contract back towards the burner outlet port resulting in combustion taking place inside the burner
expansion of the burning surface to the point where burning ceases at the burner outlet port and bums above it
2.7.10 yellow tipping
incomplete combustion where excess hydrocarbons can possibly result in unacceptable levels of carbon monoxide being produced
NOTE This may result in soot deposition and continual deterioration of combustion.
addition of odorants, generally strongly offensive smelling organic sulfur compounds, to natural gas (normally odourless) to allow gas leaks to be recognized by smell at trace levels (before accumulating to dangerous concentrations in air)
"strong" smelling organic chemical or combination of chemicals (e.g. sulfur compounds) added to fuel gases to impart a characteristic and distinctive (usually disagreeable) warning odour so as to be enable the detection of gas leaks by smell
2.8.3 odoriferous sulfur compound
organic sulfur compound used for fuel gas odorization
NOTE Odoriferous sulfur compounds belong to one of the following classes of substances:
— alkyi sulfides (thioethers);
— cyclic sulfides (thioethers);
— alkane thiols (alkyi mercaptans).
cyclic organic sulfur compound with one suifur atom incorporated in the hydrocarbon ring (C4H8S) and often used for natural gas odorization
Subscripts, symbols and units
A.1 Symbols and subscripts
a, b, c, d polynomial coefficients
b gas law deviation coefficient (b = 1-Z)
d relative density 1
f supercompressibility factor
H molar basis calorific value MJ/mol
H mass basis calorific value MJ/kg
H volumetric basis calorific value MJ/m3
h molar enthalpy J/mol
K relative response factor 1
k number of components detected in the chromatogram
L molar enthalpy of vaporization of water kJ/mol
M mass per mole kg/kmol
p (absolute) pressure kPa
R gas constant (8,314 510) J/(K-mol)
RA,B chromatographic resolution between peaks for components A and B
Rf chromatographic response factor counts
s standard deviation
T thermodynamic (absolute) temperature K
r Celsius temperature °C
tR (A), tR(B) chromatographic retention time for components A and B min
V volume m3
Vm molar volume . m3/kmol
W Wobbe index MJ/m3
w(A), w(B) chromatographic peak widths at baseline for components A and B min
x mole fraction or normalized mole fraction 1
x* non-normalized mole fraction 1
y volume fraction 1
Z compressibility factor
ρ density kg/m3
ρm molar density kmol/m3
A, B components A and B
crc combustion reference conditions
i component i
m quantity per mole
mc main and associated components
mrc metering reference conditions
oc other components
rc reference component
src standard reference conditions
tc trace components
wrm working reference gas mixture (WRM)
A.2 Conversion factors for pressure, temperature, length and energy
To convert from
kPa to bar =>
MPa to bar => bar = MPa·10
atm to bar => 10 bar= atm • 1,013 25
psia to bar =>
psig to bar =>
To convert from
K to ºC => ºC=K-273,15
ºF to ºC => ºC=
ºR to ºC => ºC=ºR·1,8 - 273,15
To convert from
foot to m => m = foot • 0,304 8
To convert from BTU to J => J = BTU • 1,055
A.3 List of abbreviations
ASTM American Society for Testing and Materials
CEN European Committee for International Standardization
IEC International Electrotechnical Commission
IGU International Gas Union
ISO International Organization for Standardization
CD Chemiluminescence detector
CNG Compressed natural gas
CRM Certified reference gas mixtures
ED Electrochemical detector
FID Flame ionization detector
FPD Flame photometric detector
HWD Hot wire detector
LDS Local distribution system
LNG Liquefied natural gas
LPG Liquid petroleum gas
NG Natural gas
RM Reference material
PSM Primary standard gas mixture
SNG Substitute natural gas
TCD Thermal conductivity detector
VIM International vocabulary of basic and general terms in metrology (see reference  of the Bibliography)
WRM Working reference gas mixtures
 ISO 3534-1, Statistics — Vocabulary and symbols — Part 1: Probability and general statistical terms
 ISO 4260, Petroleum products and hydrocarbons — Determination of sulfur content — Wickbold combustion method
 ISO 6142, Gas analysis — Preparation of calibration gas mixtures — Gravimetric methods
 ISO 6143, Gas analysis — Comparison methods for determining the composition of calibration gas mixtures
 ISO 6326-1, Natural gas — Determination of sulfur compounds — Part 1: General introduction
 ISO 6326-2, Gas analysis — Determination of sulfur compounds in natural gas — Part 2: Gas chromatographic method using an electrochemical detector for the determination of odoriferous sulphur compounds
 ISO 6326-3, Natural gas — Determination of sulfur compounds — Part 3: Determination of hydrogen sul-fide, mercaptan sulfur and carbonyl sulfide sulfur by potentiometry
 ISO 6326-4, Natural gas — Determination of sulfur compounds — Part 4: Gas chromatographic method using a flame photometric detector for the determination of hydrogen sulfide, carbonyl sulfide and other suifur-containing odorants
 ISO 6326-5, Natural gas — Determination of sulfur compounds — Part 5: Lingener combustion method
 ISO 6327, Gas analysis — Determination of the water dew point of natural gas — Cooled surface condensation hygrometers
 ISO 6568, Natural gas — Simple analysis by gas chromatography
 ISO 6570-1, Natural gas — Determination of potential hydrocarbon liquid content— Part 1: Principles and general requirements
 ISO 6570-2, Natural gas — Determination of potential hydrocarbon liquid content — Part 2: Weighing method
 ISO 6570-3:19843), Natural gas— Determination of potential hydrocarbon liquid content— Part 3: Volumetric method
 ISO 6974-1, Natural gas— Determination of composition with defined uncertainty by gas chromatography — Part 1: Guidelines for tailored analysis
 ISO 6974-2, Natural gas — Determination of composition with defined uncertainty by gas chromatography — Part 2: Measuring-system characteristics and statistics for processing of data
 ISO 6974-3, Natural gas— Determination of composition with defined uncertainty by gas chromatography — Part 3: Determination of hydrogen, helium, oxygen, nitrogen, carbon dioxide and hydrocarbons up to Cg using two packed columns
ISO 6974-4, Natural gas— Determination of composition with defined uncertainty by gas chromatogra-pny— part 4: Determination of nitrogen, carbon dioxide and C^ to Cg and Cg+ hydrocarbons for a laboratory and on-line measuring system using two columns
 ISO 6974-5, Natural gas— Determination of composition with defined uncertainty by gas chromatogra-phy— Part 5: Determination of nitrogen, carbon dioxide and C-s to Cg and Cg+ hydrocarbons for a laboratory and on-line process application using three columns
 ISO 6974-6:—4^, Natural Gas — Determination of composition with defined uncertainty by gas chromatog-raphy— Pan. 6: Determination of hydrogen, helium, oxygen, nitrogen, carbon dioxide and hydrocarbons up to Co using three capillary columns
 ISO 6975, Natural gas — Extended analysis — Gas chromatographic method
 ISO 6976:1995, Natural gas— Calculation of calorific values, density, relative density and Wobbe index from composition
 ISO 6978-1:—5), Natural gas — Determination of mercury — Part 1: Principles and general requirements
 ISO 6978-2:—5), Natural gas — Determination of mercury — Part 2: Sampling of mercury by chemisorption on iodine
 ISO 6978-3:—5), Natural gas — Determination of mercury — Part 3: Sampling of mercury by amalgamation on gold/platinum alloy
 ISO 7504:—6\ Gas analysis — Vocabulary  ISO 10101 –1, Natural gas — Determination of water by the Kart Fischer method — Part 1: Introduction
 ISO 10101-2, Natural gas — Determination of water by the Karl Fischer method— Part 2: Titration procedure
 ISO 10101 -3, Natural gas — Determination of water by the Karl Fischer method — Part 3: Coulometric procedure
 ISO 10241, International terminology standards — Preparation and layout
 ISO 10715, Natural gas — Sampling guidelines
 ISO 10723, Natural gas — Performance evaluation for on-line analytical system
 ISO 11095, Linear calibration using reference materials
 ISO 11541, Natural gas — Determination of water content at high pressure
 ISO 12213-1, Natural gas — Calculation of compression factor — Part 1: Introduction and guidelines
 ISO 12213-2, Natural gas— Calculation of compression factor— Part 2: Calculation using a molar-composition analysis
 ISO 12213-3, Natural gas — Calculation of compression factor — Part 3: Calculation using physical properties
 ISO 13443, Natural gas — Standard reference conditions
 ISO 13686, Natural gas — Quality designation
 ISO 13734, Natural gas — Organic sulfur compounds used as odorants — Requirements and test methods
 ISO 14111, Natural gas — Guidelines for traceability in analysis
 ISO 15403, Natural gas — Designation of the quality of natural gas for use as a compressed fuel for vehicles
 ISO Guide 30, Terms and definitions used in connection with reference materials
 Guide to the expression of uncertainty in measurement (GUM). BIPM, IEC, IFCC, ISO, IUPAC, IUPAP, OIML, 1st ed., corrected and reprinted in 1995
 International vocabulary of basic and general terms in metrology (VIM). BIPM, IEC, IFCC, ISO, IUPAC, IUPAP, OIML, 2nd ed., 1993
 ASTM D 4150-00, Standard Terminology Relating to Gaseous Fuels
absolute measurement 22.214.171.124 absorption 126.96.36.199 absorption cell 2.4.13 accuracy of measurement 188.8.131.52 adsorption 184.108.40.206 aliquot part 220.127.116.11 alkanethiol 18.104.22.168.1 alky! disulfide 22.214.171.124.3 alkyi mercaptan 126.96.36.199.1 alkyi sulfide 188.8.131.52.2 associated components 184.108.40.206.2 auxiliary gases 2.4.5
back-pressure regulator 220.127.116.11
bridge component 18.104.22.168.6
bypass line 22.214.171.124
calibration 126.96.36.199 calibration interval 188.8.131.52 carbonyl sulfide 184.108.40.206.4 carbonyl sulfide sulfur 220.127.116.11.5 carrier gas 2.4.4 CD 2.4.6 certified reference
material 18.104.22.168.1.2 chemiluminescence detector 2.4.6 chromatographic
resolution 22.214.171.124.6 CNG 126.96.36.199
combustion method 188.8.131.52 combustion reference
conditions 184.108.40.206 compressed natural gas 220.127.116.11 compression factor 18.104.22.168 condenser 22.214.171.124 control chart 126.96.36.199 control gas 188.8.131.52.2.4 control method 184.108.40.206 COS 2.5,3.3.4 critical value 220.127.116.11 CRM 18.104.22.168.12 cyclic sulfide 22.214.171.124.6
delivery point 126.96.36.199 density 188.8.131.52 desorption 184.108.40.206
direct chromatographic measurement of components 220.127.116.11.6 direct measurement 18.104.22.168 direct sampling 22.214.171.124 drip pots 126.96.36.199 dry natural gas 188.8.131.52
electrochemical detector 2.4.7 enthalpy of transformation 184.108.40.206 enthalpy of transition 220.127.116.11 etalon 18.104.22.168.1.5
family of gases 2.7.2
fast loop 22.214.171.124
feeding station 126.96.36.199
flame ionization detector 2.4.8
flame photometric detector 2.4.1
flash back 2.7.8
floating piston cylinder 188.8.131.52
gas analysis 184.108.40.206.5 gas chromatograph 2.4.3 gas chromatographic
method 220.127.116.11 gas composition 18.104.22.168.4 gas compressibility factor 22.214.171.124 gas family 2.7.2 gas group 2.7.3 gas quality 126.96.36.199 gas sorption effects 188.8.131.52 gas liquid separator 184.108.40.206 glycol 220.127.116.11.7
group of components 18.104.22.168.4 group of gases 2.7.3 group standard 22.214.171.124.1.6
heating device 126.96.36.199
high pressure natural gas 188.8.131.52
hot loop 184.108.40.206
hot wire detector 2.4.9
hydrocarbon dew point 220.127.116.11.1
hydrogen sulfide (H^S) 18.104.22.168.8
ideal gas 22.214.171.124 incremental sampler 126.96.36.199 indirect chromatographic measurement of components 188.8.131.52.7 indirect measurement 184.108.40.206 indirect sampling 220.127.116.11 inferential measurement 18.104.22.168 inferior calorific value 22.214.171.124 injection point 126.96.36.199 in-line instrument 188.8.131.52 integrator 2.4.11 interchangeabiiity 2.7.1 international measurement
standard 184.108.40.206.1.9 introduction unit 2.4.2
lean gas 220.127.116.11
limit gases 2.7.5
liquefied natural gas 18.104.22.168
local distribution system 22.214.171.124
low pressure natural gas 126.96.36.199
main component 188.8.131.52.1 major components 184.108.40.206.1 manufactured gas 220.127.116.11 mass [molar]
concentration 18.104.22.168.2 mass [volume] [mole]
fractions 22.214.171.124.1 material measure 126.96.36.199 measurement reference
system 188.8.131.52.1 measurement method for direct
properties 184.108.40.206 measurement standard 220.127.116.11.1.5 measuring system 2.4.1 mercaptan 18.104.22.168.9 mercaptan sulfur 22.214.171.124 metering reference
conditions 126.96.36.199 methane number 188.8.131.52 methanol 184.108.40.206.11 minor component 220.127.116.11.2 mole 2:18.104.22.168 multi-point calibration 22.214.171.124
standard 126.96.36.199.1.10 natural gas 188.8.131.52 NG 184.108.40.206
normal pressure 2.7.6 normal reference
conditions 220.127.116.11 normalization 18.104.22.168.5
odorant 2.8.2 odoriferous sulfur
compound 2.8.3 odorization 2.8.1 off-line instrument 22.214.171.124 on-line instrument 126.96.36.199 organic sulfur 188.8.131.52.12 other components 184.108.40.206.5 other constituents 220.127.116.11.5 outlet station 18.104.22.168 outlier 22.214.171.124
photometry 2.4.12 pipeline grid 126.96.36.199 potential hydrocarbon liquid
content 188.8.131.52.3 potentiometric method 184.108.40.206 potentiometric titration 220.127.116.11 precision 18.104.22.168 primary standard 22.214.171.124.1.7 primary standard gas
mixture 126.96.36.199.2.1 proportional-flow incremental
sampler 188.8.131.52 PSM 184.108.40.206.2.1 purging time 220.127.116.11
raw gas 18.104.22.168
reference component 22.214.171.124.6
reference gas 2.7.4
reference material 126.96.36.199.1.1
system 188.8.131.52.1.3 reference standard 184.108.40.206.1.11 regulator 220.127.116.11 relative density 18.104.22.168 relative measurement 22.214.171.124 relative response factor 126.96.36.199.3 repeatability limit 188.8.131.52 representative sample 184.108.40.206 reproducibility limit 220.127.116.11 residence time 18.104.22.168 response 22.214.171.124.1
response factor 126.96.36.199.2 response function 188.8.131.52.4 retrograde condensation 184.108.40.206.2 rich gas 220.127.116.11 RM 2.5.3,5.1.1
sample container 18.104.22.168 sample line 22.214.171.124 sample probe 126.96.36.199 sampling point 188.8.131.52 secondary standard 184.108.40.206.1.8 secondary standard gaz
mixture 220.127.116.11.2.2 sequential F-test 18.104.22.168 series of standards 22.214.171.124.1.6 single-point-calibration 126.96.36.199 SNG 188.8.131.52 sour gas 184.108.40.206 spot sample 220.127.116.11 standard reference
conditions 18.104.22.168 straggler 22.214.171.124 substitute natural gas 126.96.36.199 sulfide 188.8.131.52.13 superior calorific value 184.108.40.206 synthetic gas 220.127.116.11
test pressure 2.7.7 tetrahydrothiophene 2.8.4 thermal conductivity detector 2.4.9 thioether 18.104.22.168.14,22.214.171.124.2,
126.96.36.199.6 thiol 188.8.131.52.16
thiol (mercaptan) sulfur 2.5-3.3.15 THT 2.8.4
total sulfur 184.108.40.206.17 trace component 220.127.116.11.3 trace constituent 18.104.22.168.3 traceability 22.214.171.124.1.4 transfer line 126.96.36.199 transfer standard 188.8.131.52.1.13 transformation 184.108.40.206 trueness 220.127.116.11 turbidimetric titration 18.104.22.168
U uncertainty 22.214.171.124
V verification 126.96.36.199
water content 188.8.131.52.2 water dew point 184.108.40.206.1 wet gas 220.127.116.11 Wobbe-index 18.104.22.168 working reference gas
mixture 22.214.171.124.2.3 working standard 126.96.36.199.1.12 WRM 188.8.131.52.2.3
Y yellow tipping 2.7.10