A natural-gas processing plant in Aderklaa, Austria

Natural-gas processing is a range of industrial processes designed to purify raw natural gas by removing contaminants such as solids, water, carbon dioxide (CO2), hydrogen sulfide (H2S), mercury and higher molecular mass hydrocarbons (condensate) to produce pipeline quality dry natural gas[1] for pipeline distribution and final use.[2] Some of the substances which contaminate natural gas have economic value and are further processed or sold. Hydrocarbons that are liquid at ambient conditions: temperature and pressure (i.e., pentane and heavier) are called natural-gas condensate (sometimes also called natural gasoline or simply condensate).

Raw natural gas comes primarily from three types of wells: crude oil wells, gas wells, and condensate wells. Crude oil and natural gas are often found together in the same reservoir. Natural gas produced in wells with crude oil is generally classified as associated-dissolved gas as the gas had been associated with or dissolved in crude oil. Natural gas production not associated with crude oil is classified as “non-associated.” In 2009, 89 percent of U.S. wellhead production of natural gas was non-associated.[3] Non-associated gas wells producing a dry gas in terms of condensate and water can send the dry gas directly to a pipeline or gas plant without undergoing any separation processIng allowing immediate use.[4]

Natural-gas processing begins underground or at the well-head. In a crude oil well, natural gas processing begins as the fluid loses pressure and flows through the reservoir rocks until it reaches the well tubing.[5] In other wells, processing begins at the wellhead which extracts the composition of natural gas according to the type, depth, and location of the underground deposit and the geology of the area.[2]

Natural gas when relatively free of hydrogen sulfide is called sweet gas; natural gas that contains elevated hydrogen sulfide levels is called sour gas; natural gas, or any other gas mixture, containing significant quantities of hydrogen sulfide or carbon dioxide or similar acidic gases, is called acid gas.

Types of raw-natural-gas wells

Contaminants in raw natural gas

See also: Natural-gas condensate

Raw natural gas typically consists primarily of methane (CH4) and ethane (C2H6), the shortest and lightest hydrocarbon molecules. It often also contains varying amounts of:

Natural gas quality standards

Raw natural gas must be purified to meet the quality standards specified by the major pipeline transmission and distribution companies. Those quality standards vary from pipeline to pipeline and are usually a function of a pipeline system's design and the markets that it serves. In general, the standards specify that the natural gas:

Seasonal variation of hydrocarbon dewpoint
Hydrocarbon dewpoint 30 °F (–1.1 °C) 35 °F (1.7 °C) 40 °F (4.4 °C) 45 °F (7.2 °C) 50 °F (10 °C)
Months December

January

February

March

April

November

May

October

June

September

July

August

The natural gas should:

Description of a natural-gas processing plant

There are a variety of ways in which to configure the various unit processes used in the treatment of raw natural gas. The block flow diagram below is a generalized, typical configuration for the processing of raw natural gas from non-associated gas wells showing how raw natural gas is processed into sales gas piped to the end user markets.[15][16][17][18][19] and various byproducts:

Raw natural gas is commonly collected from a group of adjacent wells and is first processed in a separator vessels at that collection point for removal of free liquid water and natural gas condensate.[23] The condensate is usually then transported to an oil refinery and the water is treated and disposed of as wastewater.

The raw gas is then piped to a gas processing plant where the initial purification is usually the removal of acid gases (hydrogen sulfide and carbon dioxide). There are several processes available for that purpose as shown in the flow diagram, but amine treating is the process that was historically used. However, due to a range of performance and environmental constraints of the amine process, a newer technology based on the use of polymeric membranes to separate the carbon dioxide and hydrogen sulfide from the natural gas stream has gained increasing acceptance. Membranes are attractive since no reagents are consumed.[24]

The acid gases, if present, are removed by membrane or amine treating and can then be routed into a sulfur recovery unit which converts the hydrogen sulfide in the acid gas into either elemental sulfur or sulfuric acid. Of the processes available for these conversions, the Claus process is by far the most well known for recovering elemental sulfur, whereas the conventional Contact process and the WSA (Wet sulfuric acid process) are the most used technologies for recovering sulfuric acid. Smaller quantities of acid gas may be disposed of by flaring.

The residual gas from the Claus process is commonly called tail gas and that gas is then processed in a tail gas treating unit (TGTU) to recover and recycle residual sulfur-containing compounds back into the Claus unit. Again, as shown in the flow diagram, there are a number of processes available for treating the Claus unit tail gas and for that purpose a WSA process is also very suitable since it can work autothermally on tail gases.

The next step in the gas processing plant is to remove water vapor from the gas using either the regenerable absorption in liquid triethylene glycol (TEG),[12] commonly referred to as glycol dehydration, deliquescent chloride desiccants, and or a Pressure Swing Adsorption (PSA) unit which is regenerable adsorption using a solid adsorbent.[25] Other newer processes like membranes may also be considered.

Mercury is then removed by using adsorption processes (as shown in the flow diagram) such as activated carbon or regenerable molecular sieves.[7]

Although not common, nitrogen is sometimes removed and rejected using one of the three processes indicated on the flow diagram:

NGL fractionation train

The NGL fractionation process treats offgas from the separators at an oil terminal or the overhead fraction from a crude distillation column in a refinery. Fractionation aims to produce useful products including natural gas suitable for piping to industrial and domestic consumers; liquefied petroleum gases (Propane and Butane) for sale; and gasoline feedstock for liquid fuel blending.[29] The recovered NGL stream is processed through a fractionation train consisting of up to five distillation towers in series: a demethanizer, a deethanizer, a depropanizer, a debutanizer and a butane splitter. The fractionation train typically uses a cryogenic low temperature distillation process involving expansion of the recovered NGL through a turbo-expander followed by distillation in a demethanizing fractionating column.[30][31] Some gas processing plants use lean oil absorption process[27] rather than the cryogenic turbo-expander process.

The gaseous feed to the NGL fractionation plant is typically compressed to about 60 barg and 37 °C.[32] The feed is cooled to -22 °C, by exchange with the demethanizer overhead product and by a refrigeration system and is split into three streams:

The overhead product is mainly methane at 20 bar and -98 °C. This is heated and compressed to yield a sales gas at 20 bar and 40 °C. The bottom product is NGL at 20 barg which is fed to the deethanizer.  

The overhead product from the deethanizer is ethane and the bottoms are fed to the depropanizer. The overhead product from the depropanizer is propane and the bottoms are fed to the debutanizer. The overhead product from the debutanizer is a mixture of normal and iso-butane, and the bottoms product is a C5+ gasoline mixture.

The operating conditions of the vessels in the NGL fractionation train are typically as follows.[29][33][34]

NGL column operating conditions
Demethanizer Deethanizer Depropanizer Debutanizer Butane Splitter
Feed pressure 60 barg 30 barg
Feed temperature 37 °C 25 °C 37 °C 125 °C 59 °C
Column operating pressure 20 barg 26-30 barg 10-16.2 barg 3.8-17 barg 4.9-7 barg
Overhead product temperature -98°C 50 °C 59 °C 49 °C
Bottom product temperature 12 °C 37 °C 125 °C 118 °C 67 °C
Overhead product Methane (natural gas) Ethane Propane Butane Isobutane
Bottom product Natural gas liquids (Depropanizer feed) (Debutanizer feed) Gasoline Normal Butane

A typical composition of the feed and product is as follows.[32]

Stream composition, % volume
Component Feed NGL Ethane Propane Isobutane n-Butane Gasoline
Methane 89.4 0.5 1.36
Ethane 4.9 37.0 95.14 7.32
Propane 2.2 26.0 3.5 90.18 2.0
Isobutane 1.3 7.2 2.5 96.0 4.5
n-Butane 2.2 14.8 2.0 95.0 3.0
Isopentane 5.0 33.13
n-Pentane 3.5 0.5 23.52
n-Hexane 4.0 26.9
n-Heptane 2.0 13.45
Total 100 100 100 100 100 100 100

Sweetening Units

The recovered streams of propane, butanes and C5+ may be "sweetened" in a Merox process unit to convert undesirable mercaptans into disulfides and, along with the recovered ethane, are the final NGL by-products from the gas processing plant. Currently, most cryogenic plants do not include fractionation for economic reasons, and the NGL stream is instead transported as a mixed product to standalone fractionation complexes located near refineries or chemical plants that use the components for feedstock. In case laying pipeline is not possible for geographical reason, or the distance between source and consumer exceed 3000 km, natural gas is then transported by ship as LNG (liquefied natural gas) and again converted into its gaseous state in the vicinity of the consumer.

Products

The residue gas from the NGL recovery section is the final, purified sales gas which is pipelined to the end-user markets. Rules and agreements are made between buyer and seller regarding the quality of the gas. These usually specify the maximum allowable concentration of CO2, H2S and H2O as well as requiring the gas to be commercially free from objectionable odours and materials, and dust or other solid or liquid matter, waxes, gums and gum forming constituents, which might damage or adversely affect operation of the buyers equipment. When an upset occurs on the treatment plant buyers can usually refuse to accept the gas, lower the flow rate or re-negotiate the price.

Helium recovery

If the gas has significant helium content, the helium may be recovered by fractional distillation. Natural gas may contain as much as 7% helium, and is the commercial source of the noble gas.[35] For instance, the Hugoton Gas Field in Kansas and Oklahoma in the United States contains concentrations of helium from 0.3% to 1.9%, which is separated out as a valuable byproduct.[36]

See also

References

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  2. ^ a b Speight, James G. (2015). Handbook of Petroleum Product Analysis, Second Edition. Hoboken, NJ: John Wiley & Sons. p. 71. ISBN 978-1-118-36926-5.
  3. ^ "Archived copy" (PDF). Archived from the original (PDF) on 2016-03-05. Retrieved 2014-09-21.((cite web)): CS1 maint: archived copy as title (link)
  4. ^ Kidnay, Arthur J.; Parrish, William R.; McCartney, Daniel G. (2019). Fundamentals of Natural Gas Processing, Third Edition. Boca Raton, FL: CRC Press. p. 165. ISBN 978-0-429-87715-5.
  5. ^ Agency, United States Central Intelligence (1977). Natural Gas. Washington, D.C.: U.S. Central Intelligence Agency. p. 25.
  6. ^ a b U.S. Crude Oil Production Forecast- Analysis of Crude Types (PDF), Washington, DC: U.S. Energy Information Administration, 29 May 2014, p. 7, A final point to consider involves the distinction between the very light grades of lease condensate (which are included in EIA's oil production data) and hydrocarbon gas liquids (HGL) that are produced from the wellhead as gas but are converted to liquids when separated from methane at a natural gas processing plant. These hydrocarbons include ethane, propane, butanes, and hydrocarbons with five or more carbon atoms – referred to as pentanes plus, naptha, or plant condensate. Plant condensate can also be blended with crude oil, which would change both the distribution and total volume of oil received by refineries.
  7. ^ a b c "Mercury Removal from Natural Gas and Liquids" (PDF). UOP LLC. Archived from the original (PDF) on 2011-01-01.
  8. ^ "Radium in Piping".
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  10. ^ Institute of Petroleum (1978). A guide to North Sea oil and gas technology. London: Heyden & Son. p. 133. ISBN 0855013168.
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  12. ^ a b Glycol Dehydration Archived 2009-09-12 at the Wayback Machine (includes a flow diagram)
  13. ^ Desulfurization of and Mercury Removal From Natural Gas Archived 2008-03-03 at the Wayback Machine by Bourke, M.J. and Mazzoni, A.F., Laurance Reid Gas Conditioning Conference, Norman, Oklahoma, March 1989.
  14. ^ Using Gas Geochemistry to Assess Mercury Risk Archived 2015-08-28 at the Wayback Machine, OilTracers, 2006
  15. ^ Natural Gas Processing: The Crucial Link Between Natural Gas Production and Its Transportation to Market Archived 2011-03-04 at the Wayback Machine
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  26. ^ Gas Processes 2002, Hydrocarbon Processing, pages 84–86, May 2002 (schematic flow diagrams and descriptions of the Nitrogen Rejection and Nitrogen Removal processes)
  27. ^ a b Market-Driven Evolution of Gas Processing Technologies for NGLs Advanced Extraction Technology Inc. website page
  28. ^ AET Process Nitrogen Rejection Unit Advanced Extraction Technology Inc. website page
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  30. ^ Cryogenic Turbo-Expander Process Advanced Extraction Technology Inc. website page
  31. ^ Gas Processes 2002, Hydrocarbon Processing, pages 83–84, May 2002 (schematic flow diagrams and descriptions of the NGL-Pro and NGL Recovery processes)
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  35. ^ Winter, Mark (2008). "Helium: the essentials". University of Sheffield. Retrieved 2008-07-14.
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Further reading