Natural-gas processing

• Crude oil wells: Natural gas that comes from crude oil wells is typically called associated gas. This gas could exist as a separate gas cap above the crude oil in the underground reservoir or could be dissolved in the crude oil, ultimately coming out of solution as the pressure is reduced during production. Condensate produced from oil wells is often referred to as lease condensate. • Dry gas wells: These wells typically produce only raw natural gas that contains no condensate with little to no crude oil and are called non-associated gas. Condensate from dry gas is extracted at gas processing plants and is often called plant condensate. • Condensate wells: These wells typically produce raw natural gas along with natural gas liquid with little to no crude oil and are called non-associated gas. Such raw natural gas is often referred to as wet gas. • Coal seam wells: These wells typically produce raw natural gas from methane deposits in the pores of coal seams, often existing underground in a more concentrated state of adsorption onto the surface of the coal itself. Such gas is referred to as coalbed gas or coalbed methane (coal seam gas in Australia). Coalbed gas has become an important source of energy in recent decades. ==Contaminants in raw natural gas==

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: • Heavier gaseous hydrocarbons: propane (C3H8), normal butane (n-C4H10), isobutane (i-C4H10) and pentanes. All of these are collectively referred to as Natural Gas Liquids or NGL and can be processed into finished by-products. • Liquid hydrocarbons (also referred to as casinghead gasoline or natural gasoline) and/or crude oil. • Acid gases: carbon dioxide (CO2), hydrogen sulfide (H2S) and mercaptans such as methanethiol (CH3SH) and ethanethiol (C2H5SH). • Other gases: nitrogen (N2) and helium (He). • Water: water vapor and liquid water. Also dissolved salts and dissolved gases (acids). • Mercury: minute amounts of mercury primarily in elemental form, but chlorides and other species are possibly present. • Naturally occurring radioactive material (NORM): natural gas may contain radon, and the produced water may contain dissolved traces of radium, which can accumulate within piping and processing equipment; rendering piping and equipment radioactive over time. == 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: • Be within a specific range of heating value (caloric value). For example, in the United States, it should be about 1035 ± 5% BTU per cubic foot of gas at 1 atmosphere and 60 °F (41 MJ ± 5% per cubic metre of gas at 1 atmosphere and 15.6 °C). In the United Kingdom the gross calorific value must be in the range 37.0 – 44.5 MJ/m3 for entry into the National Transmission System (NTS). • Be delivered at or above a specified hydrocarbon dew point temperature (below which some of the hydrocarbons in the gas might condense at pipeline pressure forming liquid slugs that could damage the pipeline.) Hydrocarbon dew-point adjustment reduces the concentration of heavy hydrocarbons so no condensation occurs during the ensuing transport in the pipelines. In the UK the hydrocarbon dew point is defined as <-2 °C for entry into the NTS. The natural gas should: • Be free of particulate solids and liquid water to prevent erosion, corrosion or other damage to the pipeline. • Be dehydrated of water vapor sufficiently to prevent the formation of methane hydrates within the gas processing plant or subsequently within the sales gas transmission pipeline. A typical water content specification in the U.S. is that gas must contain no more than seven pounds of water per million standard cubic feet of gas. In the UK this is defined as <-10 °C @ 85barg for entry into the NTS. ==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. and various byproducts: • Natural-gas condensate • Sulfur • Ethane • Natural gas liquids (NGL): propane, butanes and C5+ (which is the commonly used term for pentanes plus higher molecular weight hydrocarbons) 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. 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. 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), 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. using low temperature distillation. This process can be modified to also recover helium, if desired (see also industrial gas). • Absorption process, using lean oil or a special solvent as the absorbent. • Adsorption process, using activated carbon or molecular sieves as the adsorbent. This process may have limited applicability because it is said to incur the loss of butanes and heavier hydrocarbons. 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. 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. Some gas processing plants use lean oil absorption process 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: • Condensed liquid passes through a Joule-Thomson valve reducing the pressure to 20 bar and enters the demethanizer as the lower feed at -44.7 °C. • Some of the vapour is routed through a turbo-expander and enters the demethanizer as the upper feed at -64 °C. • The remaining vapor is chilled by the demethanizer overhead product and Joule-Thomson cooling (through a valve) and enters the column as reflux at -96 °C. A typical composition of the feed and product is as follows. 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. == See also ==