How Do You Process Natural Gas?


What is Natural Gas, anyway?

Natural-gas processing is a complex industrial process designed to clean raw natural gas by separating impurities and various non-methane hydrocarbons and fluids to produce what is known as pipeline quality dry natural gas

Natural-gas processing begins at the well head. The composition of the raw natural gas extracted from producing wells depends on the type, depth, and location of the underground deposit and the geology of the area. Oil and natural gas are often found together in the same reservoir. The natural gas produced from oil wells is generally classified as associated-dissolved, meaning that the natural gas is associated with or dissolved in crude oil. Natural gas production absent any association with crude oil is classified as “non-associated.”

 

Why Do We Process it and How?

The natural gas used by consumers in its final state varies greatly than the natural gas underground. The final product contains almost pure methane, but raw natural gas contains a variety of impurities. Impurities include carbon dioxide, hydrogen sulfide, water vapor, oil, nitrogen, hydrates and heavier hydrocarbons, consisting mostly of ethane, propane, butane and pentanes [1]. While some processing is done at the well site, the complete processing takes place at a processing plant. Removal of all or most impurities is required before entering the pipeline. Although processing has several steps, there are four main processes: oil, condensate and water removal, carbon dioxide and hydrogen sulfide removal, dehydration, and NGL removal.

After leaving the gas well, the first step in processing is removing oil, water and condensates. This step is typically done at the well site. First, heaters and scrubbers are used to prevent the temperature of the gas from dropping too low and remove large-particle impurities, respectively.

Second, the oil is separated from the gas with a conventional separator. The separator consists of a closed tank that separates the liquids and solids by the force of gravity [1]. When gravity alone does not separate the two, separators use pressure to cool the gas, then moves through a high pressure liquid at a low temperature to ‘knockout’ any remaining oil and a portion of the water [1].

Once the oil, water and condensates have been removed, the carbon dioxide and hydrogen sulfide must be removed if present. This step is known as ‘sweetening’ the gas, due to sulfur’s scent, otherwise known as “sour” gas. This step is very important because hydrogen sulfide is extremely harmful, even lethal, and very corrosive. Required preventative measures are put in place by OSHA, Occupational Safety and Health Administration, and NSC, National Safety Council, while regulations and product specifications are made by NACE International, National Agency of Corrosion Engineers, to prevent its effects. Croft’s GSSGas Sweetening System, removes both CO2 and H2S. This is done by first removing all H2S, followed by the removal of CO2 up to the Amine System’s ability. If any CO2 remains, it will be removed during the next cycle. The Amine System can also be used to remove high levels of H2S. If COremovals not needed, Croft’s HRS, H2S Removal System, strictly removes H2S by means of injecting H2S scavenger into the system.

After hydrogen sulfide and carbon dioxide has been removed, the natural gas must be dehydrated. Dehydration is imperative to remove the excess water which creates hydrates, corrosion, freezing issues and does not meet pipeline requirements of 7/MMcf. Water is removed in the form of water vapor and can be done through absorption or adsorption. Adsorption is the collection and condensing of water vapor on the surface, which is done with Croft’s PDS, Passive Dehydration System. Absorption, completed with a Glycol unit, is the removal of water vapor by a dehydrating agent. Unlike the Glycol unit, Croft’s PDS has zero emissions, is not carcinogenic and is environmentally friendly. You can learn more about the difference between adsoprtion vs. absorption here

 

 

The removal of mercury is not always necessary, but high amounts cause corrosion of aluminum heat exchangers and environmental pollution. If needed, the two forms of removal are regenerative and nonregenerative processes. The regenerative process uses sulfur- activated carbon or alumina, while nonregenerative uses silver on molecular sieve [2].

Nitrogen is an inert gas, non-flammable, and lowers the temperature of natural gas. Natural gas’ gross heating value must be between 900-1200 British thermal units (btu) [3]. Pure natural gas is almost all methane, which has a heating value of 1010 btu. When nitrogen is present in pure natural gas, it lowers the gross heating value too much to meet pipeline requirements. When this occurs nitrogen must be removed, known as nitrogen rejection.

NGL’s or natural gas liquids are heavy hydrocarbons including ethane, propane, butane, iso-butane, and natural gasoline. These natural gas liquids have a high BTU and are not pipeline quality, but they are a very valuable by-product when sold separately. The process of removing NGL’s is known as NGL recovery. The amount of NGL’s are measured by gallons per 1,000 cubic feet (gpm), with 1-2 gpm being ‘lean’ or dry, and > 4 gpm being ‘very rich’ or wet [4]. The first step of NGL Recovery is to remove all NGL’s from the natural gas.  This can be done with Croft’s JTS, Joule-Thomson System, which removes both heavy hydrocarbons and hydrates. They are removed by cooling the gas temperature, which turns the vapor into liquid for easy removal. The ‘richer’ the NGL’s, the higher the need for the JTS, which also lowers the gross heating value and removes hydrates. After the NGL’s are removed they are separated into individual products, known as fractionation. Separated NGL’s have a higher selling value, and can be used in a multitude of ways. The equipment used to separate the ethane, propane, butanes and pentanes by volatility is known as the fractionator train [5].



Check out the Croft Production Systems customizable product line below!

Product Line  

 

References:

  1. 2011, “Processing Natural Gas,” NaturalGas.org. http://www.naturalgas.org/naturalgas/processing_ng.asp
  2. Kidnay, A., McCartney, D., Parrish, W., 2011, “Fundamentals of Natural Gas Processing,” CRC Press, (2), 319-321.
  3. Hyne, N., 2001, “Nontechnical Guide to Petroleum Geology, Exploration, Drilling, and Production,” PennWell Books, (2), 10-13.
  4. 2012, “How Rich is Rich?- How BTU Content and GPM Determine NGL Quantities,” RBN Energy, LLC. http://www.rbnenergy.com/how-rich-is-rich-how-btu-content-and-gpm-determine-ngl-quantities-part-II
  5. Manning, F., Thompson, R., 1991, “Oilfield Processing of Petroleum Volume One: Natural Gas,” PennWell Books, 1, 339-340.