At the point of extraction, natural gas comprises 20 or more individual hydrocarbon and non-hydrocarbon constituents. Methane is the major component, typically between 60 to 90%, with other components present in different proportions, from high percentages to traces at less than 0.01%. Undesirable non-hydrocarbon constituents include carbon dioxide, hydrogen sulfide and moisture. As well as methane, other hydrocarbon constituents include ethane (C2H6), propane (C3H8), and butane (C4H10).
Initial processing dries the gas to remove liquid water and reduce water vapor concentration. Further processing removes CO2 and H2S before reduced temperature separation extracts entrained condensates and reduces the concentration of non-methane hydrocarbons such as the natural gas liquids (NGLs) – ethane, propane, butane, iso-butane and natural gasoline. The result is a gas mixture with a high proportion of methane, but which still contains varying amounts of ethane, propane, and butane.
So the term ‘natural gas’ describes a gas mixture that contains a wide range of hydrocarbons, from light short chain aliphatics (non-aromatic compounds) to heavy, long chain molecules.
Hydrocarbon dew point (HCDP) indicates the temperature at which heavy hydrocarbon components begin to condense out of the gaseous phase when the gas is cooled at constant pressure. It’s sometimes referred to as “hydrocarbon liquid drop-out”.
Therefore, a higher HCDP normally indicates a higher proportion of heavy hydrocarbon components. This is an important parameter for pipeline operators: if the natural gas contains a high proportion of heavy hydrocarbons there is a greater risk of liquid condensate forming in the pipeline.
The HCDP is defined as the series of matching pressure and temperature points at which hydrocarbons condense into liquid from a natural gas mixture. It is typically displayed on a phase diagram (see below) as a function of gas pressure and temperature, for natural gas with a given composition. The dew point line divides the two-phase gas-liquid region and the single-phase gas region. Two dew point temperatures are possible at a given pressure and two dew point pressures are possible at a given temperature.
This phase envelope phenomenon provides for behavior known as retrograde condensation. The word “retrograde” means moving backward and this phenomenon was given the name because it is contradictory to the phase behavior of pure components, which condense with increasing pressure and/or decreasing temperature. The maximum pressure at which liquids can form is called the cricondenbar, and the maximum temperature at which liquids can form is called the cricondentherm. Note that given the shape of the phase envelope, the measurement of hydrocarbon dew point and potential hydrocarbon liquid is usually carried out at a pressure between 25 and 30 bar (ideally 27 bar) where liquid drop out occurs at the highest temperatures. When condensate forms from a gas mixture, the distribution of hydrocarbons changes so that the liquid phase becomes enriched in the heavier components while the gas phase becomes depleted of these heavier components. As the gas is cooled below its original dew point temperature, the entire dew point curve shifts cooler for the remaining gas phase that is now depleted in heavier components. The chilled gas temperature becomes the new HCDP of the gas stream.
Hydrocarbon Dew Point (HCDP) is not an easy parameter to measure. Gas composition, contaminants and additives, high pressures, and the presence of corrosive compounds vary from pipeline to pipeline and all affect the results of measurements.
The HCDP is very sensitive to the specific components of the gas stream and is strongly influenced by the concentration of the heavier hydrocarbons, especially C6+. The presence of heavier hydrocarbons will increase the HCDP and failure to include them in a HCDP calculation will under-predict the HCDP. Therefore, an accurate determination of the HCDP requires evaluation of distribution of the individual components in the C6+ fraction (at least C9 but possibly higher).
There are a number of different accepted methods for measuring hydrocarbon dew point which have been developed over time.
Online optical hydrocarbon dew-point analyzers
These analyzers use a chilled mirror sensor to determine the hydrocarbon dew-point temperature of the gas sample accurately and automatically. Their main advantage is the reliable repeatability of the measurements – unlike the manual dew scope described below, the measurements a completely objective and automatic. There is no requirement for specialist operators and the overall running costs are low – although there is a significant capital investment.
Michell Instruments’ Condumax II Hydrocarbon Dew-Point Analyzer uses the Dark Spot technique – which is a variation of the chilled mirror dew-point sensor – to provide continuous and accurate measurements of HCDP. Water dew-point measurements are also available using the same analyzer, using Michell’s ceramic metal oxide moisture sensor.
Manual chilled mirror hydrocarbon dew-point testers
Intended for making spot checks of natural gas quality in pipelines and for verifying the measurements of other hydrocarbon dew point analyzers, hydrocarbon dew-point testers are portable instruments designed for easy use by a lone engineer in the field.
As well as their portability, the key advantage of the manual dew-point testers is their low capital investment. However, they are only recommended as a maintenance tool or to carry out spot checks at point where no online analyzer is installed.
Despite their convenience, there are several disadvantages, including high running costs. Although the instrument itself is simple, using it is highly labor-intensive and requires highly trained staff. The measurements themselves are subjective as they depend on the judgement of the operator. No matter how experienced and well-trained the operators are, measurement accuracy will vary between each individual to a certain extent. Because of these factors, manual chilled mirror dew scopes are only suited for periodic spot checks of gas quality.
The original technique for measuring hydrocarbon dew point was to use a chilled mirror dew scope. This is a manual method which requires a skilled operator to view the formation of condensate on a chilled mirror and use their judgement to determine the dew-point temperature.
High-resolution video for reliable, repeatable measurements
Recent developments in newer models of portable dew-point test have overcome many of the disadvantages and limitations of older instruments.
Michell Instrument’s CDP301 Condumax Dew Point Tester uses the fundamental chilled mirror technique but reduces the reliance on the judgement of an operator to accurately record the dew-point temperature. The CDP301 uses high-definition video to display the formation of condensate on a screen, making it easy for users to determine the exact dew-point temperature with a click of a button. The video is also recorded to provide an accurate record of all measurements for later analysis. The CDP301 is also able to measure water dew point using the same chilled mirror sensor.
Gas chromatograph (GC) for in-depth analysis of gas composition
Used appropriately, a gas chromatograph allows users to further analyze the exact composition of their natural gas. This method determines the concentrations of each hydrocarbon element (up to C12 in most cases). A gas chromatograph such as the LDetek MultiDetek2-EX enables users to:
However, a GC is not an ideal solution for monitoring the process because it uses calculated values to determine the hydrocarbon dew point. An online hydrocarbon dew-point analyzer – such as the Condumax II - is the most efficient and cost-effective method to monitor the process and detect process upset conditions, with a secondary GC used to provide additional analysis data.
Hydrocarbon dew point and processing natural gas are complex topics. Please get in touch with us if you have any comments to make on this article or would like to discuss it further.
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