gas quality matters

Written by Matt Shaw, Business Development Manager, CAC Gas & Instrumentation

What is Gas Quality?

Natural Gas is made up of several component gases and is therefore subject to natural variation. This inconsistency affects the energy contained within a given volume of gas. Gas quality is most commonly described based on the measurements taken of the heating value, also known as calorific value, Wobbe Index, relative density, among others.

Measuring Gas Quality


Gas quality is measured mostly for fiscal purposes. Fiscal measurement as a general term means “measurement for money” and may be performed for either allocation or custody transfer purposes.

Allocation is the numerical distribution of product between parties according to their equity share. Custody transfer is typically contract driven. A custody transfer point does not necessarily imply a change of ownership. It may be that at this point a measurement of the natural gas is taken to ensure that the contractual obligation between buyer and seller is being met. The obligation may require adherence to accuracy, linearity, repeatability or uncertainty standards as defined by the measurement standards they have agreed to operate under.


Gas quality is most commonly measured with the use of a Gas Chromatograph. A gas chromatograph is used to separate the components of a natural gas so that each major component can be quantified. The internal process consists of subsystems that inject the sample, separate the sample, detect the components and report the results.

Difficulties in Measuring Natural Gas

Natural gases from different sources have different compositions and hence different properties. Natural gas is not a formulated product and because of shared pipelines with a single delivery point, the compositions of the gas can be vastly different.

Natural gas distribution systems will have specifications defined in terms of limits for properties and/or composition. Where supplies are significantly different, the distributor has the option of blending to satisfy specification (e.g. Wobbe index requirements).

Gas quality measurements of composition are carried out to demonstrate compliance with a specification and to ensure that a customer is billed for the correct energy content delivered.

Commercial Measurements

To determine the financial value of natural gas, both gas quality (calorific value) and gas quantity (flow) must be measured. The combination of the two measurements provide total energy. The total energy value is used to calculate the financial value of the gas.

Calorific Value (CV)

The calorific value can be summarised as a measurement of the amount of energy released when a known volume of gas is completely combusted under specific conditions. It is the measure of the heating power of gas, as a number of kilowatt hours / megajouls / therms delivered. The range of CV is often specified in natural gas regulations.

The importance of CV

Natural gas is bought and sold in units of volume as a source of energy and CV is a key element in the equation. Total energy is calculated by multiplying the amount of gas (quantity) by its heating value (CV).

CV information can be used to determine the amount of energy transported by the pipeline operators, distribution networks, gas shippers and for billing customers for energy consumption.

Ways of Measuring CV
  • Combustion calorimeters
  • Gas chromatographs (GCs)
  • Inferential devices

Combustion Calorimetry

Combustion calorimetry measures the heat released from a controlled flow of gas. This requires some cumbersome equipment setup in a temperature controlled room and gives only the CV information. Calorimetry has been superseded by gas chromatography (GC) which also provides composition data.

Gas Chromatography

Process gas chromatographs separate natural gas into its constituent compounds (i.e. methane, ethane, carbon dioxide etc.) and measure the amount of each component in the gas. The physical characteristics of each component, as defined by ISO6976 are programmed into the chromatograph and an overall CV is derived from the measured composition.

The determination of the CV of gas is carried out in accordance with international standards. These regulations stipulated when and where the CV of gas is measured and the type of instrument to be used.

Inferential Techniques

Inferential devices measure particular physical characteristics of the gas from which a simplified composition is inferred. This defines the gas as composed of nitrogen, carbon dioxide, ethane and propane, and calculates properties according to ISO7976. This technique is usually faster and easier to use than a calorimeter and carrier gases are not required.

The problem with the inferential techniques is that there is currently no procedure in place to test the performance of the instrument. The performance of GC measurement though, can be evaluated using ISO10723 which uses a range of natural gas like test gases to assess error and bias due to repeatability and linearity.


Why are GCs the Preferred Option?

A GC is simpler and cheaper to install than a combustion calorimeter and measures significantly more data that just calorific value. A GC measures the compositional data of the gas directly from which the calculation of range of properties can be made and can be setup to analyser components in 5 minutes or less. At present, GCs tend to be more accurate than inferential devices.


Superior CV and Inferior CV

Two terms you will come across when looking at CV data is superior and inferior CV. But what is the difference?

Superior CV is the theoretical value, based on calculation of the properties of the gas mixture. Billing is most often based on the superior CV measurement.

Inferior CV however is the actual energy derived from the combustion of the gas and is always lower than the superior CV because of the latent heat of vaporisation of water. When hydrocarbons are burnt in air, it forms CO2 and water. Water will be vaporised which requires energy hence inferior CV includes this loss of energy into its calculations.


The Compression Factor

The compression factor is the ratio of the molar volume of a gas to the molar volume of an ideal gas at the same temperature and pressure. More simply, some gases are more compressible than others. In a defined space, the volume of gas that will fit depends on how compressible it is. This is described by the compression factor.

The compression factor is calculated using the ideal gas equation. It varies with temperature, pressure and composition. For hydrocarbons gases and their mixtures the compression factor is always less than 1. This means that a defined volume of gas at a defined pressure will contain more moles than predicted from ideal behaviour. At ambient conditions the compression factor for most natural gasses will be around 0.997. ISO6976 gives a method for calculation of the compression factor at ambient conditions. It is an approximation but is fit for purpose.

Measuring the Compression Factor

The compression factor is not usually specified by regulations but must be measured. Measurements can be made by sophisticated laboratory apparatus, on-line with densitometers or calculated from GC composition. Measurement by GC is becoming more popular, particularly with hydrocarbon wet gases, where a droplet of liquid on the densitometer will throw the results out.


Typical Composition of Natural Gas

Natural gas is typically made up of mostly Methane in the range of 80% to 95%. Other Major components include hydrocarbons ethanes (C2) to butanes (C4) and non-flammable components include nitrogen and carbon dioxide. Minor components may include hydrocarbons from pentanes (C5) to dodecanes (C12); inert gases helium and argon, as well as water and hydrogen sulphide.

Looking at the Components in More Detail:


Making up the bulk of natural gas, hydrocarbons are compounds made from carbon and hydrogen atoms only. There are different types of hydrocarbons including saturated hydrocarbons, most commonly known as alkanes and unsaturated hydrocarbons, most commonly known as alkenes. Cycloalkanes (e.g. cyclopentane, methylhexane) and aromatic hydrocarbons including benzene, toluene and xylene.

These compounds are measured by the analytical technique of gas chromatography (GC). The physical properties of each component are defined by ISO6976 and are programmed into the chromatograph. From the composition using a weighted average method the following properties can be calculated:

  • Calculation of calorific vales, density, relative density and Wobbe index
  • Molar mass and atomic indices
  • Summation factors
  • Atomic weights of the elements

Water (moisture)

Water vapour can also be present in natural gas, which can condense into liquid water. If the temperature decreases or the pressure increases water will drop out of the gas phase.

Water can settle at certain points in the pipeline and a “slug” is formed, these slugs can cause mismeasurement as well as damage to pipelines and associated equipment.

Liquid water present in a high pressure pipeline will enhance the corrosive effect of acid gases such as H2S and CO2. When producing LNG the gas is liquefied at near-atmospheric pressure by cooling it to -162°C, so removal of moisture is crucial to avoid ice crystals from forming.

Carbon Dioxide (CO2) and Nitrogen (N2)

Both CO2 and N2 are colourless, odourless gases present at varying amounts in natural gas, both gases are easily measured using gas chromatography with a thermal conductivity detector (TCD)

Measurement is required for the same reason we measure hydrocarbons. CO2 and N2 both affect the physical properties, have high molecular weights but zero heating value and can affect the Wobbe index.

Argon (Ar) and Helium (He)

Both gases are present at ppm levels in natural gas (trace components). These gases are not measured by process GC’s as they have no significant effect on the physical properties. Instead, fixed amounts are assumed to be in the gas stream.

Hydrogen Sulphide (H2S)

H2S is a colourless, toxic gas with a characteristic rotten egg smell (fatal concentrations can anesthetize the sense of smell!) It is both corrosive and flammable. Most natural gases contain very low levels of sulphur by comparison with other fossil fuels (ppm levels) however some sources do have higher levels.

Total sulphur (including COS)

Carbonyl Sulphide (COS), a rarer natural gas component than H2S, is in itself not a problem so limit values are not usually specified. However, under certain conditions it can be converted into H2S. Other sulphurs present can include mercaptans, disulphides and thiophenes. Total sulphur is simply the sum of the amounts of all the sulphur containing species in the gas.

Why do we measure H2S and total sulphur?

  • Public safety (high levels can be fatal)
  • Reduced corrosion in pipelines and associated equipment
  • Contractual agreements
    • A specification limit for H2S alone: 15 to 20 mg/m3
    • A specification limit for total sulphur (inc. H2S): 50 mg/m3
    • Measured at network entry and custody transfer points
  • Control odour – other sulphur species are added to odorise the gas to aid in leak detection.
  • Can be removed from natural gas – “sweetening”

Oxygen (O2)

Oxygen is not present in natural gas although it can enter via leaks in the production or transport system. Oxygen can cause various problems including corrosion in pipelines and explosions! Strict limit specifications are set and it will be extracted if levels are too high.

Hydrogen (H2)

Hydrogen while being the most abundant chemical substance in the universe, has only trace amounts in natural gas. Like argon and helium, hydrogen is not measured by process GC’s as it contributes very little to the properties of natural gas.


Other Considerations for Natural Gas:

Relative Density

Relative density is the ratio of the density of the gas at standard pressure and temperature to the density of air at the same standard pressure and temperature. The density of natural gas is important for the calculation of flow (volume) and therefore the financial value of natural gas.

Hydrocarbon dewpoint

The hydrocarbon dewpoint is the temperature (at a defined pressure) at which hydrocarbon components in natural gas will start to condense out of the gas phase. At the dewpoint trace amounts of liquid phase will separate from the gas. As the temperature falls further, increasing amounts of liquids are formed.

In a natural gas transmission system any liquid formation creates a problem and should be avoided. Filters can be blocked and any liquid droplets entering appliances can create operation difficulties.

In simple gas mixtures behaving nearly ideally, the dewpoint temperature would be expected to increase with increasing pressure. The higher pressure will increase the partial pressure of a condensable component until it reaches the saturation vapour pressure.

Hydrocarbon mixtures do not behave ideally, but display retrograde behaviour, whereby the dewpoint temperature increases as the pressure falls.

Detailed analysis of the composition of natural gas using GC can be used to calculate dewpoint temperature using an equation of state.

The advantage of this approach is that the entire phase diagram can be derived, hence

  • Dewpoint at any pressure, including the cricondentherm and cricondenbar
  • Critical point
  • The amount and composition of condensate at any point within the phase boundary.


Gas quality parameters defined to ensure gas supplied from different sources (different compositions) will not affect the safe operation of gas appliances. Two key measures are the Wobbe Index and the incomplete combustion factor.

Wobbe Index (WI)

Most appliances control the flow of gas to a burner by providing a fixed pressure of gas to an orifice. The Wobbe Index is calculated by the ratio of calorific value (CV) to the square root of the relative density (RD) and is a measure of the heat supplied to a burner. Gases of different composition but similar WI values will provide similar heat output. 

Gas with a high Wobbe Index produces a large flame with potential for toxic CO to be produced. Gas with a low Wobbe Index causes a higher flame speed and potential for flame lift.

Incomplete Combustion Factor (ICF)

The incomplete combustion factor relates the Wobbe Index to the combustion performance of an appliance (CO/CO2 ratio)



Gas quality is measured for a few key reasons:

  • Financial
    • To calculate from the properties the value of the gas
    • Allocation from shared pipelines
  • Safety
    • To ensure is isn’t a hazard to personnel or equipment
  • Maintaining operations
    • To ensure the gas can be transmitted and distributed to customers without interruption or operational difficulties.

When measuring natural gas the main components to be measured are:

  • Hydrocarbons
  • Hydrogen sulphide
  • Carbon Dioxide
  • Total sulphur
  • Total inert gases
  • Water

From this composition data the properties to be calculated include:

  • Calorific Value (CV)
  • Relative Density (RD)
  • Wobbe Index
  • Incomplete Combustion Factor (ICF)
  • Hydrocarbon dewpoint
  • Compression factors

The most common way of measuring natural gas is the gas chromatograph (GC) A GC is simpler and cheaper to install than a combustion calorimeter and measures more data than just calorific value. A GC measures the compositional data of the gas directly from which the calculation of range of properties can be made. It can be setup to analyse components in 5 minutes or less and tend to be more accurate than inferential devices.

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