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Natural-gas processing
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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

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  • 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.[6]
  • 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.[6]
  • 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

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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

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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).[9]
  • 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.[9] The hydrocarbon dewpoint changes with the prevailing ambient temperature, the seasonal variation is:[10]
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:

  • 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.[11][12] In the UK this is defined as <-10 °C @ 85barg for entry into the NTS.[9]
  • Contain no more than trace amounts of components such as hydrogen sulfide, carbon dioxide, mercaptans, and nitrogen. The most common specification for hydrogen sulfide content is 0.25 grain H2S per 100 cubic feet of gas, or approximately 4 ppm. Specifications for CO2 typically limit the content to no more than two or three percent. In the UK hydrogen sulfide is specified ≤5 mg/m3 and total sulfur as ≤50 mg/m3, carbon dioxide as ≤2.0% (molar), and nitrogen as ≤5.0% (molar) for entry into the NTS.[9]
  • Maintain mercury at less than detectable limits (approximately 0.001 ppb by volume) primarily to avoid damaging equipment in the gas processing plant or the pipeline transmission system from mercury amalgamation and embrittlement of aluminum and other metals.[7][13][14]

Description of a natural-gas processing plant

[edit]

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:

  • Cryogenic process (Nitrogen Rejection Unit),[26] using low temperature distillation. This process can be modified to also recover helium, if desired (see also industrial gas).
  • Absorption process,[27] using lean oil or a special solvent[28] 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

[edit]

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 bar 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:

  • 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.[32]

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

[edit]

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

[edit]

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

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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

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References

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Further reading

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Revisions and contributorsEdit on WikipediaRead on Wikipedia

Natural-gas processing

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from Grokipedia
Natural gas processing is the treatment of raw extracted from wells to remove impurities such as , , , , , and other contaminants, while also separating valuable natural gas liquids (NGLs) like , , , and , resulting in pipeline-quality dry suitable for transportation and end-use. This essential industrial process ensures the gas meets strict quality specifications for heating value, pressure, and purity to prevent in pipelines, formation, and hazards during distribution. The primary purpose of natural gas processing is to transform "wet" gas—raw production containing liquids and impurities—into "dry" methane-rich gas that complies with interstate standards, while recovering NGLs for separate markets such as feedstocks, heating fuels, and transportation. , processing plants handled 26.1 trillion cubic feet of wet in 2023, contributing to a total dry natural gas production of 37.8 trillion cubic feet. Processing capacity and throughput have expanded significantly since 2004 to accommodate rising production from formations. Globally, natural gas processing is critical for meeting international and LNG specifications, with the U.S. leading in production and exports as of 2023. Processing is typically performed at centralized facilities connected to gathering , but initial separation may occur at the using simpler . Key steps in natural gas processing form a sequential series of unit operations tailored to the composition of the incoming gas stream, which varies by reservoir. These include:
  • Initial separation: Raw gas passes through gas-oil-water separators and condensate separators to remove free liquids like oil, water, and heavier hydrocarbons under reduced pressure.
  • Dehydration: Water vapor is extracted using glycol absorption or solid desiccants to prevent pipeline corrosion and hydrate blockages.
  • Acid gas removal: Hydrogen sulfide (H₂S) and carbon dioxide (CO₂) are scrubbed out with amine solutions in a "sweetening" process, reducing corrosiveness and meeting environmental limits on sulfur emissions.
  • Mercury and other impurity removal: Trace contaminants like mercury are adsorbed to protect downstream equipment.
  • NGL recovery: Hydrocarbons heavier than methane are separated via cryogenic turboexpansion, absorption with solvents, or adsorption, often cooling the gas to -100°F or lower.
  • Nitrogen removal: Remaining nitrogen is removed from the methane stream using molecular sieves or cryogenic processes.
  • NGL fractionation: The recovered NGLs are fractionated in distillation towers based on boiling points to isolate individual components.
These operations not only enable efficient gas transmission but also contribute to the broader energy economy by producing NGLs, which in 2023 totaled 3.4 trillion cubic feet (gaseous equivalent) for significant U.S. exports and domestic use, supporting industries from plastics to residential heating. Disruptions, such as those from hurricanes, can temporarily reduce processing capacity by billions of cubic feet per day, underscoring the infrastructure's vulnerability.

Overview

Definition and purpose

Natural-gas processing refers to the set of industrial operations that purify raw extracted from underground reservoirs by removing impurities and separating valuable components, such as natural gas liquids (NGLs). This process transforms the raw stream, which often contains , (CO₂), (H₂S), and heavier hydrocarbons, into a cleaner product suitable for transportation and end-use applications. The primary purpose of natural-gas processing is to produce pipeline-quality gas, typically consisting of more than 95% with low levels of contaminants, including no more than 2-3% CO₂, less than 0.25-0.3 grains of H₂S per 100 standard cubic feet, and water content below 7 pounds per million standard cubic feet. This ensures safe and efficient transport through pipelines while recovering valuable NGLs, such as and , which are used as feedstocks in manufacturing. At a high level, the process involves initial separation of liquids from gas, followed by sweetening to remove acid gases like CO₂ and H₂S, and to eliminate , preparing the gas for distribution. Economically, is vital, enabling nearly all marketable —over 95% of global production excluding flaring—to reach consumers, primarily via domestic and international pipelines, with about 12% traded as LNG as of 2023, with individual plants typically handling capacities ranging from 10 to 1,000 million standard cubic feet per day (MMscfd).

Historical development

The processing of natural gas began in the early 19th century in the United States, where the first intentional natural gas well was drilled in 1821 by William Hart in Fredonia, New York, primarily for local lighting and heating applications with minimal treatment beyond basic separation from water and solids. Globally, natural gas processing evolved similarly, with early commercial use in the UK from the 1790s using coal gas, but true natural gas processing advanced post-World War II; liquefied natural gas (LNG) technology was developed in the U.S. in the 1940s but first commercialized in Algeria in 1964, enabling international trade. Throughout much of the 1800s and into the early 20th century, natural gas was often an associated byproduct of oil production and was frequently flared at the wellhead due to the lack of infrastructure for transportation and markets, limiting systematic processing efforts. This changed significantly after World War II, as surging domestic demand for clean-burning fuel—driven by industrial and residential growth—prompted the recovery and processing of gas to meet pipeline specifications, marking the shift toward large-scale treatment facilities. Key milestones in natural gas processing emerged in the mid-20th century, with amine-based sweetening processes becoming widespread in the to efficiently remove and from streams, enabling safer and more reliable transport. The introduction of technology in the early 1960s revolutionized natural gas liquids (NGL) recovery by harnessing expansion energy for cryogenic cooling, improving efficiency over prior absorption methods. The , triggered by oil embargoes, accelerated offshore development in the U.S., with legislative changes like the 1978 Outer Continental Shelf Lands Act amendments promoting expedited exploration and processing technologies adapted for marine environments. Technological advances continued into the 1980s, when cryogenic processes gained prominence for their superior NGL recovery rates and energy efficiency compared to earlier lean-oil absorption techniques, becoming standard in high-volume plants. By the , growing environmental regulations spurred the integration of CO2 capture technologies in natural gas processing, building on decades of removal expertise to sequester emissions for or storage, aligning with global climate goals. The post-2010 shale gas boom in the U.S., fueled by hydraulic fracturing and horizontal drilling, dramatically expanded processing capacity, with modular plants enabling rapid deployment in remote shale plays like the Marcellus and Permian basins to handle surging wet gas volumes. This era also drove trends toward integrating natural gas processing with (LNG) export facilities, transforming the U.S. into a leading global supplier and optimizing NGL extraction for feedstocks. By 2023, the U.S. became the top global LNG exporter, with exports reaching 91.2 million metric tons, further integrating processing with export infrastructure, though a 2024 policy review by the Department of Energy introduced uncertainties for future expansions as of 2025.

Raw natural gas

Sources and well types

Raw originates from various geological formations and production activities, with primary sources including associated gas, non-associated gas, and minor contributions from and . Associated gas, produced alongside crude from , accounts for approximately 30-40% of total natural gas production in the United States as of 2023, depending on regional oilfield dynamics. This gas is separated from the at the wellhead or during processing, and its volume often correlates with output fluctuations. Non-associated gas, extracted from dedicated dry gas reservoirs without significant co-production, constitutes the majority of supply in gas-prone basins. , recovered from seams through dewatering processes, represents a smaller share, about 2% of U.S. production as of 2022. —generated from of organic waste—remains a minor source, contributing less than 1% globally as of 2024 (approximately 40 billion cubic meters), but with growing potential through upgrading. Natural gas wells are classified by extraction method and location, influencing production efficiency and infrastructure needs. Conventional wells, typically vertical and drilled into permeable reservoirs like or , allow gas to flow naturally to the surface without extensive stimulation. Unconventional wells, prevalent in low-permeability formations, employ horizontal combined with hydraulic fracturing to access resources such as ; these have transformed supply since the 2010s, with U.S. production contributing over 60% of domestic output and driving global market growth. Offshore subsea wells, drilled from platforms or floating vessels in ocean depths exceeding 1,000 meters, target deepwater reservoirs and often integrate subsea tiebacks to surface facilities for gas gathering. Geothermal-associated gas, a niche source from hot rock formations, is minimal and typically co-produced in limited volcanic regions, though not a primary commercial contributor. Global raw production reached approximately 4 trillion cubic meters annually in recent years, with 2024 estimates at 4.12 trillion cubic meters, underscoring its scale as a key energy commodity. In the United States, the leading producer at over 1 trillion cubic meters in 2024, developments have accounted for about 60% of supply since the 2010s, rising to nearly 80% of output by 2024 through technological advances. Wells are further categorized by flow regimes based on gas composition, affecting handling and processing. Sweet wells produce gas with low (H₂S) content, below 4 parts per million (ppm), posing fewer and safety risks. Sour wells, containing H₂S above 4 ppm, require specialized safety measures due to the gas's toxicity. Rich gas wells yield streams with high liquids (NGL) content, exceeding 3 gallons per thousand cubic feet (gal/Mscf), enabling valuable condensate recovery. Lean gas wells, with NGL below 3 gal/Mscf, produce drier methane-dominant flows suited for direct transport. These characteristics vary by type, with associated gas often richer and potentially sourer than non-associated sources.

Composition and contaminants

Raw natural gas is predominantly composed of (CH₄), which typically accounts for 70-90% of its volume by mole percent. This primary component is accompanied by other hydrocarbons, including ethane (C₂H₆) at 0-20%, (C₃H₈), butanes (C₄H₁₀), and traces of pentanes and higher-molecular-weight hydrocarbons (C₅+). These heavier hydrocarbons contribute to the gas's potential for natural gas liquids (NGL) recovery, though their proportions vary significantly. Contaminants in raw natural gas include acid gases such as (CO₂), which can constitute up to 50% in certain reservoirs, and (H₂S), which defines when present at levels up to 30%. is another common impurity, reaching saturation levels equivalent to up to 7 lb per million standard cubic feet (lb/MMSCF). Trace elements like mercury (0.01-180 μg/Nm³), BTX aromatics (, , ), and particulates from reservoir formations also occur, posing risks to equipment and safety if not addressed. The composition of raw natural gas exhibits considerable variability depending on the geological reservoir. For instance, gas is often lean, with low concentrations of heavier hydrocarbons, and , containing minimal H₂S and CO₂. In contrast, Middle Eastern fields frequently yield with elevated CO₂ levels and significant H₂S content. Such differences arise from formation conditions, influencing processing needs. Analysis of raw composition relies on , which separates and quantifies , inert gases, and contaminants like CO₂ and H₂S using detectors such as thermal conductivity (TCD) or flame ionization (FID). calculations assess potential for liquid formation under varying and temperature, aiding in contaminant evaluation.

Processing requirements

Quality standards

Quality standards for processed natural gas ensure safe transportation, compatibility with infrastructure, and suitability for end uses such as power generation and heating. These standards primarily focus on achieving high content while limiting contaminants that could cause , formation, or combustion issues. According to specifications outlined by the American Gas Association (AGA) and the (ISO 13686), pipeline-quality typically contains greater than 95% by volume, with (H₂S) limited to less than 4 parts per million by volume (ppmv), (CO₂) below 2% by volume, and not exceeding 7 pounds per million standard cubic feet (lb/MMSCF) to prevent in pipelines. Regional variations reflect local infrastructure, regulatory priorities, and gas sources. In the United States, the (FERC) oversees interstate pipelines, where total sulfur content limits vary by pipeline tariff approved by FERC, commonly up to 20 grains per 100 standard cubic feet (≈28 lb/MMSCF) to minimize emissions and equipment damage. In the , the EN 437 standard defines gas quality for appliance compatibility, requiring a higher heating value (HHV) between 34 and 44 megajoules per cubic meter (MJ/m³) for families H and L to ensure consistent combustion performance. Testing methods verify compliance with these criteria through standardized measurements of key properties. The calorific value, expressed as HHV, is typically around 1020 British thermal units per standard cubic foot (Btu/scf) for pipeline gas, determined via methods like ASTM D3588 to assess content. The , calculated as the HHV divided by the of the gas's specific , serves as a primary metric for interchangeability, ensuring that gases with varying compositions deliver similar heat input to burners and turbines without adjustments, with typical values ranging from 1300 to 1400 Btu/scf for . The evolution of these standards has been driven by technological and environmental needs. Following the 1970s energy crisis and the rise of gas turbine-based power generation, specifications tightened to protect turbine blades from sulfur and particulate corrosion, with organizations like the AGA updating guidelines to enforce stricter H₂S and total sulfur limits. In the 2020s, standards are adapting to accommodate blending with renewables, such as up to 20% hydrogen or biogas, by expanding allowable ranges for lower-BTU content and adjusted Wobbe indices to support decarbonization without major infrastructure overhauls. As of 2025, ongoing pilots under the U.S. Department of Energy's HyBlend program demonstrate safe blending up to 20% hydrogen, prompting updates to Wobbe index ranges in standards like those from AGA and ISO to facilitate decarbonization.

Pipeline and end-use specifications

Natural gas pipelines in the United States typically operate at pressures ranging from 500 to 1,500 psig to facilitate efficient long-distance transportation while maintaining flow rates and safety margins. These pressures are regulated under federal standards to ensure structural integrity and prevent leaks, with stations used to sustain the required levels along the transmission network. To avoid condensation and liquid dropout during transport, pipeline specifications mandate strict dew point limits: the hydrocarbon dew point is controlled to avoid liquid hydrocarbon dropout, typically below 15-20°F at delivery pressure, and water content is limited to 4-7 lb per million standard cubic feet (MMscf), corresponding to a water dew point that prevents condensation at operating pressures (often around 32°F or lower at line pressure). These thresholds prevent hydrate formation and corrosion in the pipeline infrastructure. For end-use applications, distributed to residential heating systems requires odorization through the addition of mercaptans, such as ethyl mercaptan, at concentrations of about 1 lb per million cubic feet to provide a detectable "rotten egg" smell for leak safety. In power generation, the gas must have low inert content, typically less than 4% combined nitrogen and , to ensure a minimum higher heating value (HHV) of around 950-1,050 Btu/scf and optimal combustion efficiency in gas turbines. For (LNG) production and use, the processed gas achieves over 90% purity post-liquefaction, with typical compositions exceeding 85-95% to meet cryogenic storage and requirements. Custody transfer operations, where ownership changes hands, demand high-precision metering with accuracy within ±1% for to ensure fair valuation and compliance. Gas composition analysis during these transfers follows GPA Standard 2261, which outlines methods for determining hydrocarbons, inerts, and heating values with repeatability limits of ±0.05 mole percent for major components. In special cases like biomethane blending into European grids, limits are imposed to maintain compatibility, such as carbon dioxide content below 6% in countries like , to avoid impacts on materials and properties. These specifications ensure seamless integration without requiring extensive grid modifications.

Processing plant operations

Overall plant layout

processing facilities, commonly referred to as gas , vary in design and scale depending on their location and purpose. Field are typically situated near production wells to handle initial of raw gas, with capacities often ranging from 10 to 50 million standard cubic feet per day (MMscfd) to manage smaller volumes from individual or clustered wells. Central , positioned along major transmission rather than at the wellhead, process larger volumes of partially treated gas to extract residual natural gas liquids (NGLs), often handling hundreds of MMscfd to optimize transport efficiency. LNG pretreatment facilities, integrated upstream of units, focus on impurity removal tailored for cryogenic cooling, with designs accommodating high-throughput feeds up to several billion cubic feet per day while ensuring compatibility with downstream trains. The basic flow through a natural gas processing plant follows a sequential path to purify and condition the gas stream. Raw gas enters via inlet separation vessels, where free liquids such as , condensate, and solids are removed to protect downstream equipment. This is followed by removal to strip out and , then to eliminate , preventing hydrate formation and . Subsequent NGL extraction cools and separates heavier hydrocarbons, with the treated gas then undergoing to isolate individual NGL components, and final compression to meet pressure specifications. Key equipment in these facilities includes centrifugal compressors for maintaining pressure throughout the process, heat exchangers for temperature control in cooling and heating steps, and turboexpanders that harness expansion for efficient in NGL recovery. Plant construction approaches contrast modular designs, which involve prefabricated skid-mounted units assembled on-site for faster deployment and reduced labor costs, against stick-built methods that fabricate components directly at the location for customized integration but with longer timelines. Capacity and process selection scale with gas composition: turboexpander-based excel for rich gas streams high in NGLs, achieving deep cooling through work-extracting expansion, while absorption processes using lean oils suit leaner feeds with lower content for simpler contaminant capture. integration often incorporates Joule-Thomson cooling, where reduction naturally lowers temperature to aid separation without additional mechanical input. Raw gas arriving at these typically carries contaminants like , acid gases, and NGLs that necessitate this structured layout.

Acid gas removal

Acid gas removal is a critical step in natural gas processing that eliminates (H₂S) and (CO₂), collectively known as , from to produce suitable for pipeline transport and end-use applications. These contaminants are corrosive, toxic, and can interfere with downstream processes, with H₂S concentrations in sour gas ranging from parts per million to over 50 volume percent in extreme cases. The primary methods include chemical absorption using amines, physical processes, and separation, each selected based on gas composition, , and required purity. The most widely adopted technique is amine absorption, employing aqueous solutions of alkanolamines such as monoethanolamine (MEA), diethanolamine (DEA), or methyldiethanolamine (MDEA) to chemically react with acid gases in a tower. In this countercurrent , sour gas flows upward while lean amine solution flows downward, achieving 90-99% removal of H₂S and CO₂ depending on the amine type and operating conditions. The reactions are reversible acid-base interactions; for example, with a generic amine RNH₂, H₂S reacts as 2RNH₂ + H₂S ⇌ (RNH₃)₂S, while CO₂ forms RNHCOO⁻ + RNH₃⁺ via 2RNH₂ + CO₂ ⇌ RNHCOONH₃R, where R represents ethanol groups in common . The rich amine, loaded with acid gases, is then sent to a regenerator () where steam stripping at 200-240°F (93-116°C) reverses the reactions, releasing concentrated acid gas overhead and producing lean amine for recirculation. Amine system design typically features a tower with 20-40 trays to facilitate intimate gas-liquid contact, handling feeds with 10-50% total content. Lean and rich circulate in a closed loop, with pumps maintaining flow rates tailored to acid gas loading (e.g., 0.3-0.5 moles acid gas per mole for DEA). MDEA is often preferred for selective H₂S removal over CO₂ due to its tertiary structure, minimizing energy for CO₂ regeneration. Alternative processes include physical solvents like Selexol, a glycol-based solvent that absorbs acid gases under high pressure without chemical reaction, suitable for feeds with high CO₂ partial pressures and achieving near-total H₂S removal to below 0.1 ppmv. systems, using polymeric materials such as , provide bulk CO₂ separation for high-concentration feeds by selective permeation, reducing CO₂ to under 2 mol% with over 95% recovery and lower capital costs than amine units. Overall efficiencies target pipeline specifications, with amine processes routinely achieving greater than 99% H₂S removal to less than 4 ppm and CO₂ to below 2%. The removed H₂S-rich stream is typically routed to a unit, where partial combustion converts H₂S to elemental via 2H₂S + SO₂ → 3S + 2H₂O (with SO₂ from H₂S oxidation), recovering 95-98% of as a valuable .

Dehydration

Dehydration in processing involves the removal of from the gas stream to prevent formation, , and operational issues in and downstream equipment. , present as a contaminant in raw , must be reduced to meet specifications, typically below 7 lb of per million standard cubic feet (MMSCF) of gas. This is essential after acid gas removal but before liquids (NGL) recovery, as excess moisture can interfere with subsequent cooling and separation steps. The predominant method for dehydration is absorption using liquid desiccants, particularly (TEG), which achieves up to 99.9% removal. In a typical TEG unit, wet enters an absorber column operating at pressures of 500 to 1,000 psia, where it contacts lean TEG in a countercurrent flow; the glycol absorbs , producing at the top and rich glycol at the bottom. The rich glycol is then regenerated in a heated to 360–400°F, releasing while reconcentrating the TEG to 98–99% purity. Circulation rates for TEG are generally 1.5–6 gallons per pound of removed, translating to 3–10 gallons per MMSCF of gas depending on inlet content, ensuring outlet dew points as low as –100°F. Solid desiccant adsorption serves as an alternative for applications requiring ultra-low water content, such as LNG feed gas preparation, using materials like molecular sieves or in fixed-bed columns. Molecular sieves, with pore sizes of 3–4 Å, selectively adsorb water to achieve residual levels below 0.01 ppm and dew points under –100°C, while provides less stringent drying to –55°C to –60°C. These systems operate at similar pressures to glycol units but require periodic regeneration by heating the beds to 170–260°C and purging with , followed by cooling to 30–40°C before reuse; cycle times are typically 4–8 hours per bed in a multi-bed setup to maintain continuous operation. Operational challenges in dehydration units include foaming in glycol absorbers, often caused by hydrocarbon carryover or contaminants, which reduces contact efficiency and requires antifoam agents or improved inlet separation. BTEX (benzene, toluene, ethylbenzene, xylene) emissions from the regenerator are another concern, controlled by flash tanks operating at 50–100 psig to separate and recover aromatics before venting. Alternatives include partial dehydration via turboexpander cooling during NGL recovery, where gas expansion to 100–200 psia condenses water without chemicals, and methanol injection for offshore platforms, which inhibits hydrates and achieves moderate vapor removal (down to 20–50 lb/MMSCF) through direct addition at 0.5–1% volume.

Natural gas liquids recovery

Natural gas liquids (NGLs) recovery involves the extraction of heavier hydrocarbons, such as , , butanes, and , from the methane-rich stream following upstream processing steps like acid gas removal and . This process is essential to meet for heating value and to monetize valuable liquid components, typically applied to "rich" gas containing more than 2.5 gallons of NGLs per thousand cubic feet (GPM). The primary methods include cryogenic processes, absorption using heavy oils, and adsorption, each suited to different gas compositions and economic conditions. The cryogenic turboexpander process is the most widely used method for high-efficiency NGL recovery, accounting for a significant portion of modern plants due to its ability to achieve 80-95% recovery rates. In this approach, compressed inlet gas at around 550-650 psig is precooled and then expanded through a , which drops the temperature to approximately -100°F (-73°C) by converting pressure energy into , causing heavier hydrocarbons to condense. The chilled gas enters a demethanizer column, where liquids are separated from the vapor; the bottoms stream contains the recovered NGLs, while the overhead residue gas is recompressed to 800-1000 psig for . This method excels in recovering lighter components like from rich feeds and integrates via the expander driving a . Absorption methods utilize a lean oil, such as heavy hydrocarbons or specialized solvents, to selectively capture NGLs in a countercurrent absorber tower operating at elevated pressures. The rich gas contacts the descending oil, which absorbs ethane and heavier components based on their relative solubilities; typical recoveries reach about 40% for ethane and over 90% for propane and butanes. The rich oil is then heated and sent to a stripper or demethanizer to release the NGLs, regenerating the lean oil for recycle. Efficiency in absorption processes can be estimated using the Kremser equation, which relates the number of theoretical stages to the absorption factor (ratio of liquid to vapor molar flow rates adjusted for equilibrium) and inlet/outlet compositions, providing a shortcut for column design and yield prediction. This technique is simpler and less energy-intensive than cryogenic methods but less effective for ethane recovery. Adsorption processes employ solid sorbents like or in fixed-bed or (PSA) systems to selectively capture NGLs at high pressures. The gas stream passes through the adsorbent beds, where heavier hydrocarbons adhere to the surface; regeneration occurs by depressurization, heating, or purging to desorb the NGLs. These methods are particularly useful for smaller-scale or offshore applications due to their , though they typically achieve lower recoveries compared to cryogenic processes and are more common for trace component removal. Economic viability of NGL recovery hinges on market prices, with operations typically justified when the market price of provides economic incentive for recovery over rejection, typically assessed by comparing its value as a to its contribution to the BTU content of the residue gas. Recovery also stabilizes the residue gas BTU content at around 1,000-1,050 BTU/scf to comply with standards, preventing variability from fluctuating NGL content. Plant decisions often balance (e.g., $500-700 per Mcf/d for cryogenic units) against revenue from NGL sales, which can premium over by several dollars per MMBtu.

NGL fractionation

NGL fractionation is the process of separating the mixture of natural gas liquids (NGLs) into their individual components through a series of columns, enabling the production of marketable products such as , , butanes, and . The NGL feed, typically a C2+ mixture recovered upstream, enters the train, which consists of multiple towers operated in sequence to achieve high-purity separations based on differences in points. This multi-stage is essential for meeting commercial specifications and maximizing value from the hydrocarbons. The standard fractionation train comprises four main columns: a demethanizer, deethanizer, depropanizer, and debutanizer, with an optional butane splitter for further separation of normal and iso-s. The demethanizer removes residual and lighter components as overhead vapor, producing a bottoms stream rich in and heavier hydrocarbons. This stream feeds the deethanizer, where is taken as overhead vapor and propane-plus as bottoms. The depropanizer then separates as overhead from butanes and heavier as bottoms, while the debutanizer extracts butanes overhead and (C5+) as bottoms. Operations occur via multi-stage at pressures of 200-400 psig and temperatures ranging from 100-250°F, with typical ratios of 2-5:1 to optimize separation and energy use. In the sequence, lighter components like are recovered in the overhead of earlier columns, while progressively heavier fractions concentrate in the bottoms. The primary products include a Y-grade NGL mix (C2+ hydrocarbons) that may be sold as-is or further fractionated, alongside high-purity individual streams such as (>95% purity), propane (>99% purity), and iso-butane (>99% purity). These purities ensure compliance with pipeline and end-use requirements, with the debutanizer bottoms serving as . trains typically handle feed rates from 5,000 to 50,000 barrels per day (bpd), scalable based on plant design. To enhance energy efficiency, modern NGL integrates heat pumps, which can significantly reduce energy costs through heat integration and advanced configurations, with studies showing savings up to 38% compared to conventional setups. Such integrations, often involving closed-loop systems, address the high energy intensity of while maintaining product yields.

recovery

recovery from is a specialized process applied to streams with elevated helium concentrations, primarily from high-helium fields such as the Hugoton field , where helium content ranges from 0.3% to 1.9% by volume. Economic viability typically requires a minimum helium concentration of 0.3 mole percent in the feed gas, though advanced techniques like can enable recovery from lower levels down to about 0.1% in some cases. This recovery occurs downstream of natural gas liquids (NGL) extraction and nitrogen rejection, integrating into the overall plant layout to capture helium as a valuable . The primary method involves cryogenic , where the pretreated stream—already depleted of heavier hydrocarbons—is progressively cooled in heat exchangers to approximately -300°F (about 87 K), causing , , and other condensable components to liquefy and separate. The resulting vapor-rich stream, enriched in , enters a cryogenic stripping column operated under controlled pressure and temperature conditions, where is stripped overhead as a raw gas product while liquid residues are drained from the bottom. This step achieves concentrations of 70-90% with recovery rates up to 90%, depending on feed composition. Optional follows for storage or transport, using further cooling to 4 K via expansion cycles, though gaseous is often preferred for delivery. For final purification to 99.99% purity, suitable for industrial applications, pressure swing adsorption (PSA) units are employed on the crude helium stream, selectively adsorbing impurities like hydrogen, neon, and trace hydrocarbons during high-pressure cycles and desorbing them at low pressure. PSA systems, using activated carbon or molecular sieves, offer high selectivity and energy efficiency for dilute feeds, complementing cryogenic preconcentration. Alternative membrane separations are emerging for lower-concentration streams but are less common in large-scale plants due to permeability trade-offs. Globally, helium production from natural gas processing totals approximately 160 million cubic meters per year, supporting critical uses in semiconductors, , and . The has historically dominated with about 40% market share, primarily from fields like Hugoton, though this position has been affected by export restrictions from and production disruptions in during the early 2020s, contributing to ongoing global supply tightness as of 2025. As of 2025, global helium supply faces continued challenges from demand growth in high-tech sectors, with projections indicating a market balancing at around 6.5 billion cubic feet annually despite new facilities coming online.

Products and applications

Treated natural gas

Treated , also known as pipeline-quality or dry , consists primarily of with a composition exceeding 96% CH4 by volume, and less than 4% inerts such as and residual . To enhance , it is odorized by injecting trace amounts of mercaptans, such as ethyl mercaptan, which impart a distinctive rotten-egg smell detectable at concentrations well below the lower explosive limit. Following processing, the gas is compressed to transmission pipeline pressures typically ranging from 200 to 1,500 pounds per to facilitate efficient long-distance transport. The primary use of treated natural gas is transportation through interstate and intrastate pipelines, which accounts for the vast majority of its distribution to residential, commercial, and industrial end-users globally. A smaller portion is compressed further into (CNG) for use as a , particularly in fleet applications like buses and trucks, offering lower emissions compared to diesel. Additionally, it serves as a key feedstock in the production of via reforming and in synthetic natural gas (SNG) processes that upgrade to methane-rich gas. Quality assurance for treated natural gas involves rigorous final testing to ensure compliance with pipeline specifications, including levels below 4 parts per million and below 2-4% to prevent and operational issues. The gross heating value is maintained between 950 and 1,050 British thermal units per (Btu/scf) to meet end-use requirements. Globally, the volume of processed reached approximately 4.19 trillion cubic meters as of 2024, supporting diverse needs while meeting stringent purity standards.

Byproducts and their uses

Natural gas processing generates several valuable byproducts beyond the primary methane-rich treated gas, including natural gas liquids (NGLs), , and miscellaneous components like condensate, (CO2), and . These outputs are recovered during stages such as removal, , and NGL recovery, contributing significantly to the economic viability of processing plants. For instance, byproducts can account for 20-30% of a plant's , depending on market conditions and regional . In recent years, U.S. NGL exports have grown substantially, exceeding 1.5 million barrels per day as of 2024, supporting global petrochemical production. The primary byproducts are NGLs, which consist of ethane, propane, butanes (normal and iso-butane), and pentanes plus. is primarily used as a feedstock in ethylene crackers for producing and other , accounting for the vast majority of global ethane consumption. serves as a heating fuel in residential and industrial applications, and it is also exported for use in (LPG) markets, where global trade volumes are influenced by (LNG) dynamics. Butanes are commonly blended into to enhance ratings and are utilized in petrochemical processes for producing methyl tert-butyl ether (MTBE) or as refrigerants. Sulfur is another key byproduct, primarily recovered from (H2S) in streams via the during acid gas removal. Recovered from natural gas and petroleum processing contributes over 80% of the world's elemental sulfur supply, totaling approximately 68 million metric tons as of 2024. This sulfur is widely used in the manufacture of for fertilizers, as well as in rubber , pesticides, and pharmaceuticals. Additional byproducts include lease condensate, which is a light liquid hydrocarbon mixture treated as feedstock for refineries and plants; CO2, which is often reinjected for (EOR) in mature fields; and , extracted from certain high-noble gas fields and applied in , MRI machines, and . These diverse outputs not only offset processing costs but also support interconnected and industrial sectors, with their value tied to fluctuating global commodity prices.

Environmental and safety considerations

Emissions and waste management

Natural gas processing facilities generate several key emissions, primarily (CO2) from the thermal regeneration of amine solvents in acid gas removal units due to the energy-intensive heating . Volatile organic compounds (VOCs), including , , , and xylenes (BTEX), are emitted during the regeneration of (TEG) in units, where absorbed hydrocarbons are released as vapors from the still column. Flaring occurs when associated or uneconomic gas volumes are burned for or disposal, contributing to CO2, (CH4), and other GHG emissions, with global flaring releasing approximately 389 million tonnes of CO2 equivalent in 2024. Regulatory frameworks address these emissions to minimize environmental impact. In the United States, the Agency's (EPA) New Source Performance Standards (NSPS) under Subpart OOOOa limit VOC emissions from glycol dehydrators and other sources, requiring controls like condensers or incinerators. In July 2025, the EPA issued an interim final rule extending certain compliance deadlines for the 2024 and VOC standards. The European Union's Emissions Trading System (EU ETS) imposes carbon pricing on CO2 emissions from covered facilities, including natural gas processing exceeding emission thresholds, with allowance prices determined by market mechanisms to incentivize reductions. Following the 2024 EPA rules, operators must implement and repair programs using technologies like optical gas imaging to identify and mitigate fugitive CH4 emissions from processing equipment. Emissions management strategies focus on capture, recovery, and treatment to comply with regulations and reduce releases. Amine-based carbon capture systems can achieve up to 95% removal of CO2 from streams during sweetening, compressing and sequestering the captured CO2 for storage or utilization. Vapor recovery units (VRUs) installed on dehydrators and storage tanks recover VOCs and BTEX by condensing and recompressing vapors back into the process stream, often attaining 95-99% recovery efficiency and preventing atmospheric release. from processing, including high-salinity brines from removal or handling, undergoes treatment via , , and to remove contaminants before discharge or reuse, mitigating risks of and heavy metal pollution in receiving waters. Industry trends emphasize long-term decarbonization, with major natural gas companies committing to net-zero GHG emissions by 2050 through , efficiency improvements, and low-carbon alternatives. Integrating or (RNG) into processing pipelines via upgrading to biomethane specifications can reduce overall emissions by 20-30% by displacing fossil gas and capturing from organic waste sources.

Operational hazards and regulations

Natural gas processing plants face significant operational hazards primarily due to the presence of toxic and flammable components in raw gas streams. Hydrogen sulfide (H2S), a common impurity in sour gas, is highly toxic and can cause rapid loss of consciousness or death at concentrations as low as 100 parts per million (ppm), which is the Immediately Dangerous to Life or Health (IDLH) level established by the National Institute for Occupational Safety and Health (NIOSH). Methane leaks pose explosion risks, as methane is flammable with a lower explosive limit of 5% in air; concentrations exceeding 10% of the lower explosive limit are classified as IDLH by the Occupational Safety and Health Administration (OSHA) and NIOSH, potentially leading to fires or blasts if ignited. In natural gas liquids (NGL) recovery units, cryogenic processes operating at temperatures below -150°C present burn hazards from direct contact with extremely cold fluids or equipment, causing severe frostbite or tissue damage. To mitigate these risks, industry standards emphasize detection, isolation, and relief systems. Continuous H2S monitoring using fixed and portable detectors is required in areas with potential exposure, integrated with alarms and as outlined in OSHA's general industry guidelines and Recommended Practice 49 for H2S operations. Emergency shutdown systems (ESD) automatically isolate process sections upon detecting leaks or abnormal conditions, preventing escalation, while flare systems safely combust excess hydrocarbons to relieve pressure and reduce potential during upsets. The OSHA (PSM) standard (29 CFR 1910.119) mandates comprehensive hazard analyses, operating procedures, and mechanical integrity programs for facilities handling flammable gases like those in NGL recovery, ensuring proactive reduction. Regulatory frameworks enforce these mitigations through federal oversight. For offshore platforms, API Recommended Practice 14C provides guidelines for designing surface safety systems, including sensors for overpressure, leaks, and gas blowby, to protect against H2S and hydrocarbon releases. The Pipeline and Hazardous Materials Safety Administration (PHMSA) regulates pipeline integrity under 49 CFR Part 192, requiring operators to assess and repair threats like corrosion in sour gas lines to prevent leaks. Following the 2010 Deepwater Horizon incident, the Bureau of Safety and Environmental Enforcement (BSEE) implemented enhanced well control rules applicable to sour service operations, including stricter blowout preventer testing and H2S contingency planning for high-risk offshore gas wells. Historical incidents underscore the need for rigorous controls, such as unit leaks in natural gas processing plants during the , where or foaming led to H2S releases and injuries, as documented in industry failure analyses. Enhanced programs have contributed to improvements; PHMSA indicate that serious incidents in the natural gas sector declined by over 50% from the to the , correlating with operator qualification requirements that emphasize recognition and response.

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