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Gas treating and processing

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Natural gas is a mixture of many compounds, with methane (CH4) being the main hydrocarbon constituent. When natural gas is produced from an underground reservoir, it is saturated with water vapor and might contain heavy hydrocarbon compounds as well as nonhydrocarbon impurities. In the raw state, natural gas cannot be marketed and therefore must be processed to meet certain specifications for sales gas. Additionally, it might be economical to extract liquefiable hydrocarbon components, which would have a higher market value on extraction as compared with their heating value if left in the gas.

Objectives of Gas Treating and Processing

Before the optimum design of any gas treating plant can be decided, at minimum, one must know:

  • the raw gas production capability to the plant
  • composition of separator inlet gas and condensate
  • relative condensate/gas rates; specifications for the residue gas; and rate of gas sales

Consumer Expectations

The end user of natural gas needs to be assured of two conditions before committing to the use of gas in a home or factory:

  • the gas must be of consistent quality, meeting sales gas specifications
  • the supply of gas must be available at all times at the contracted rate

Gas treating facilities, therefore, must be designed to convert a particular raw gas mixture into a sales gas that meets the sales-gas specifications, and such facilities must operate without interruption.

Typical Sales Gas Specifications

Specifications for sales gas describe the required physical properties of the gas such that it can be transported under high pressure through long distance pipelines at ground temperature without forming liquids, which could cause corrosion, hydrates, or liquid slugs into downstream equipment. Limits on the content of certain nonhydrocarbon compounds are also specified. While the specific limits for each item might vary among transmission companies or customers, the overall specifications for sales gas generally include:

  • Maximum hydrocarbon dewpoint temperature at a pressure of 800 psig.
  • Maximum allowable CO2 content.
  • Maximum allowable H2S content and total organic sulfur content.
  • Maximum allowable water-vapor content.
  • Maximum allowable temperature of gas leaving the plant.
  • Minimum pressure to enter the gas transmission grid.
  • Minimum heating value.
  • Free of dust, treating chemicals, and other contaminants from the process plant.

In long distance transmission of sales gas by pipeline, the pressure is usually less than 1,000 psig. It is important that no liquids form in the line because of condensation of either hydrocarbons or water. Hydrocarbon liquids reduce the pipeline efficiency and might hold up in the line to form liquid slugs, which might damage downstream compression equipment. Condensed water can do the same. Additionally, water could form solid complexes (hydrates), which accumulate and block the line. The dewpoint temperature at any pressure is the temperature at which either hydrocarbons or water condense upon cooling of the gas. Thus, the specifications for sales gas include limits on the hydrocarbon dewpoint temperature, as well as limits on the water vapor content of the gas.

Knowing the specifications, and knowing the required sales gas flow rate and the composition of the raw gas and condensate entering the plant, the various process vessels can be designed, and the optimum process conditions of pressure and temperature can be specified.

Depending on the composition of the inlet fluids and the price at the plant gate, other sales products might be recovered in the plant as well. These could be any of the following, which also must meet stringent specifications concerning purity:

  • ethane
  • propane
  • butane and pentanes-plus

The possible processing steps, as illustrated in Fig. 5.1, are:

  • inlet separation
  • compression
  • gas sweetening
  • sulfur recovery or acid gas disposal
  • dehydration
  • hydrocarbon dewpoint control
  • fractionation and liquefied petroleum gas (LPG) recovery
  • condensate stabilization

Except for gas sweetening, the processing steps involve no chemical reactions. The gas/liquid product specifications are achieved by separating the compounds through changing the physical conditions of temperature and pressure to which the fluids are exposed. Contact with other compounds, such as glycol and absorption oil, affects the relative solubilities of certain compounds, thereby achieving separation from the main gas stream. Exposure to dry compounds, such as silica gel or molecular sieves, separate some compounds from the gas stream by physical adsorption. Distillation is used to separate the various hydrocarbon compounds into liquid fractions on the basis of differences in their volatilities.

Condensate and Oil Removal

It is necessary to extract related dissolved natural gas from the oil in which it is dissolved in order to treat and transport it. The most common method for separating natural gas from oil is to use equipment installed at or near the wellhead. The procedure for separating oil from natural gas, as well as the equipment employed, might differ significantly. Raw natural gas from various places may have varied compositions and separation needs, even though dry pipeline grade natural gas is nearly same across geographic areas.

It's possible that when this natural gas and oil is generated, it will separate on its own according to lower pressure. Oil and gas are separated rather easily, and the two hydrocarbons are transferred in different directions for further processing. A conventional separator is the most basic sort of separator. It consists of a basic closed tank in which gravity separates the heavier liquids, such as oil, from the lighter gases, such as natural gas.

Separating oil and natural gas, on the other hand, may necessitate the use of specialist equipment in some cases. The Low-Temperature Separator is an example of this sort of equipment (LTX). This is the most common designation for wells that produce high-pressure gas in addition to light crude oil or condensate. Pressure differentials are used in these separators to chill wet natural gas and separate the oil and condensate. A heat exchanger cools the wet gas as it enters the separator. After that, the gas passes through a high-pressure liquid 'knockout,' which removes any liquids and deposits them in a low-temperature separator. The gas then passes via a choke mechanism, which expands the gas as it reaches the low-temperature separator. The temperature in the separator can be lowered due to the fast expansion of the gas. Following the removal of the liquid, the dry gas returns to the heat exchanger and is warmed by the entering wet gas. It is possible to alter the temperature of the wet gas stream by adjusting the pressure of the gas in various portions of the separator. This causes the oil and some water to condense out of the wet gas stream. To extract gas from a liquid oil stream, this fundamental pressure-temperature connection may also be used in reverse.

Acid Gas Removal

Gas purification procedures range from a simple once-through wash operation to complicated multistep recycling systems. The necessity for recovery of the materials used to remove the pollutants, or even recovery of the contaminants in their original, or changed, form, causes process difficulties in many circumstances.

Adsorption and absorption are the two main methods for removing acid gases. Adsorption is a physical–chemical phenomena that occurs when a gas is concentrated on the surface of a solid or liquid in order to remove contaminants. Carbon is commonly used as an adsorbing medium because it can be regenerated after use. Adsorbents are generally granular solids having a large surface area per unit mass because the amount of material adsorbed is proportional to the surface area of the solid. The collected gas can then be desorbed with hot air or steam for either recovery or thermal destruction. Unless the gas concentration in the incoming air stream is extremely high, adsorbers are commonly utilized to enhance a low gas concentration prior to incineration. Adsorption is also used to eliminate harmful odors from gases. There are various drawbacks to using adsorption systems, but the most significant is the demand for minimizing particulate matter and/or condensation of liquids (e.g., water vapor), which can cover the adsorption surface and substantially diminish its efficacy. Absorption differs from adsorption in that it is a method of distributing the absorbed gas throughout the absorbent rather than a physical–chemical surface phenomena (liquid). Only physical solubility governs the process, which may involve chemical interactions in the liquid phase (chemisorption). Depending on the kind of gas to be absorbed, common absorption media include water, aqueous amine solutions, caustic, sodium carbonate, and non-volatile hydrocarbon oils. Plate columns or packed beds are the most common gas–liquid contactor configurations used.

Absorption is accomplished by dissolution (a physical process) or reaction (a chemical phenomenon). Sulfur dioxide is adsorbed onto a carbon surface, where it is oxidized (by oxygen in the flue gas) and absorbs moisture, resulting in sulfuric acid impregnated into and on the adsorbent.

Acid gas removal techniques now in use involve the acid gases reacting chemically with a solid oxide (such as iron oxide) or selective absorption of the pollutants into a liquid (such as ethanolamine) that is fed countercurrent to the gas. The absorbent is then stripped of its gas components (regeneration) before being recycled back to the absorber. The process design will vary, and numerous absorption and regeneration columns may be used.

Physical solvent processes and chemical solvent processes are two types of liquid absorption procedures that use temperatures below 50°C (120°F). Organic solvents, low temperatures, and high pressure are used in the previous procedures. Absorption of acid gases in chemical solvent processes is mostly accomplished using alkaline solutions such as amines or carbonates. Reduced pressures and/or high temperatures can be used to induce regeneration (desorption), in which the acid gases are removed from the solvent.

Amine washing of natural gas entails a chemical reaction between the amine and any acid gases, resulting in the release of a significant quantity of heat, which must be compensated for.

Sour Gas Sweetening

Definition of Sour Gas

Sour gas is natural gas that contains hydrogen sulfide (H2S). A natural gas is “sour” when the H2S content of the gas mixture exceeds the limit imposed by the purchaser of the gas, usually a transmission company or the end user.

  • Generally, the limit for H2S content is one grain of H2S per 100 scf of sales gas.
  • The limit for H2S content in sales gas in some areas is 1/4 grain of H2S per 100 scf of gas.
  • The mass specification of one grain per 100 scf converts a volumetric limit of 16 ppm.
  • Sour natural gases can contain H2S in concentrations from several ppm to over 90%.

While the foregoing defines sour gas from a sales gas perspective, the standards and regulations applying to sour gas service and operations may use a different definition. In this respect, the National Association of Corrosion Engineers (NACE), which developed the standards for materials for use in sour service, defines sour gas service, to which their standards apply, on the basis of partial pressure of H2S and total pressure. NACE Standard MR0175 applies to natural gas systems having a partial pressure of H2S of 0.05 psia or greater, at an absolute pressure above 65 psia. If the partial pressure of H2S is at or above these limits, the steel and other equipment exposed to the sour gas must meet the conditions specified in NACE Standard MR0175 for sour service.

Further discussion of this topic can be found on the Sour gas sweetening page.

Other Sulfur Compounds

While H2S is the compound responsible for designating a natural gas as sour, there are other sulfur compounds, also present in sour gas, in much smaller concentrations. The sales gas specifications normally set a limit of 5 grains per 100 scf of gas for total sulfur content. Thus, sweetening solvents must be able to remove other sulfur compounds, as well as H2S, from the sour gas to meet the total sulfur limitation. Some of the other common sulfur compounds found in sour natural gas are mentioned next.

Mercaptans are compounds that occur naturally in sour gas. They are hydrocarbon compounds that have a sulfur atom inserted between a carbon atom and a hydrogen atom. Some examples are:

  • methyl
  • ethyl
  • propyl
  • butyl mercaptan

Mercaptans have a strong offensive odor, and certain mixtures of manufactured mercaptan, such as tertiary butyl mercaptan and isopropyl mercaptan, as well as others, are added to sweet natural gas to odorize the gas prior to domestic or commercial consumption.

Carbon disulfide (CS2) and carbonyl sulfide (COS) might also be present in gases containing H2S, but usually only in small concentrations. These compounds also have a strong sour gas odor and are largely extracted from the sour gas in the sweetening operation.

CO2 Removal[1]

Virtually all sour natural gases also contain CO2, but the converse is not true: many natural gas mixtures can contain CO2 without any H2S. CO2 and H2S are called “acid gases,” or collectively “acid gas,” as both gases are slightly soluble in water and form a mildly acidic solution. Most regenerative processes used for H2S removal from natural gas also remove CO2. If a natural gas contains amounts of CO2 in excess of the sales gas limit, but no H2S, there are specific processes available for CO2 removal.

Sulphur Recovery[2]

Currently only two methods are available for dealing with large quantities of H2S:

• Disposal of the gas by injection into underground formations

• Conversion of the H2S into a usable product, elemental sulphur

Claus Process[3]

An initial combustion phase in a furnace is required for all Claus units. After that, the combustion products pass through a sequence of catalytic converters, each of which creates sulphur. We go over the basics of chemistry quickly before getting into the specifics of the process.

Basic chemistry:

According to the overall reaction, the Claus process consists of the vapor-phase oxidation of hydrogen sulphide to produce water and elemental sulphur:

3 H2S + 3/2 O2→ 3 H2O + (3/x) Sx.

The reaction mechanism and intermediary steps are not depicted in the above overall process. The reaction is carried out in two steps:

H2S + 3/2 O2 →H2O + SO2

2 H2S + SO2 → 2H2O + (3/x) Sx

The first reaction is a highly exothermic combustion reaction, whereas the second is a mildly exothermic reaction that is brought to equilibrium by a catalyst. The vapour is predominantly S6 and S8 at a sulphur partial pressure of 0.7 psia (0.05 bar) at temperatures below 700°F (370°C), but S2 predominates at the same partial pressure and temperatures above 1,000°F (540°C). The equilibrium constant of the reaction shifts from a downward to an upward slope as a result of the change in species. This tendency has a substantial impact on the Claus process's operation. Amorphous sulphur has a melting point of 248°F (120°C) and a typical boiling point of 832°F (445°C). The highest conversion to sulphur by the process occurs at temperatures near the melting point of sulphur, but rather high temperatures are necessary to keep sulphur in the vapour state. As a result, if the catalytic converters are used in situations where the sulphur does not condense on the catalyst, they will not be able to achieve optimal equilibrium conversion. Therefore, a succession of converters is used, with the sulphur product being removed from the reacting mixture in between converters.

Process Description

Process can be done by two different configurations: Straight through and split flow. The first reaction occurs in a combustion furnace running at near ambient pressure in the straight-through mode. The air flow rate is controlled so that one-third of the H2S, as well as any other combustibles like hydrocarbons and mercaptans, is reacted with. The exothermic H2S reaction is utilized to generate steam in a waste-heat boiler. Both reactions occur in the furnace-boiler combination, and the gases depart the waste-heat boiler at temperatures between 500- and 650-degrees Fahrenheit (260 and 343 degrees Celsius), which is above the sulphur dew point, therefore no sulphur condenses in the boiler. After the combustion furnace boiler, there are multiple catalytic reactors, but only the second reaction takes place because the furnace has used up all of the oxygen. A condenser follows each catalytic reactor to remove the sulphur produced. To eliminate elemental sulphur, the gas is cooled to 300 to 400°F (149 to 204°C) in the condenser. In most cases, the condenser cools by exchanging heat with water to produce low-pressure steam. Because the vapour leaving the condenser has reached the sulphur dew point, it is reheated before passing to the next converter to avoid sulphur deposition on the catalyst. Because the flame is not stable below 1700°F (927°C), a combustion-furnace flame temperature of 1700°F (927°C) should be maintained. Because the feed gas heating value is too low at H2S concentrations below 55 %, the straight-through design cannot be used. If the air or acid gas is warmed, concentrations as low as 40% are acceptable. The split flow design can be used for H2S concentrations ranging from 25 to 40%. The feed is split in this method, with one-third or more going to the furnace and the rest joining the furnace exit gas before entering the first catalytic converter. When two-thirds of the feed is bypassed, the combustion air is modified to convert all H2S to SO2, allowing the flame temperature to be maintained. There are two limits to the split-flow process:

1. Enough gas must be bypassed to raise the flame temperature over 1,700 0F.

2. Because one-third of the H2S must be reacted to generate SO2, the maximum bypass is two-thirds.

Containing the split-flow design and air preheating, gases with as little as 7% H2S can be treated. In the standard facilities mentioned above, sulphur recovery ranges from 90 to 96 % for two catalytic converters. For three catalytic converters, it rises to 95 to 98 %.

Dehydration of Natural Gas

Dehydration of natural gas means extracting water vapor from the gas to a specified maximum limit for residual water content. There are various processes available for dehydration, such as:

Mercury Removal[4]

Mercury is found in most natural gas fields as elemental (metallic), organic, and inorganic compounds in amounts ranging from 10 ppb to >1 ppm. During the shutdown, startup, and maintenance of gas processing units with cryogenic sections, Hg can cause serious corrosion problems. The cryogenic heat exchangers are made of a mixture of mercury and aluminum. The amalgam reacts fast in the presence of water or air, forming alumina, elemental Hg, and hydrogen, causing equipment damage. In the absence of water, Hg can cause metal embrittlement, resulting in intragranular fissures in the building material.

Non-regenerative and regenerative adsorbents can be used to remove mercury from natural gas. Hydrocarbon gas enters the top of an adsorption tower and travels downwards through the adsorbent, where the mercury is adsorbed, before exiting the bottom for further processing or sale. Regenerable systems contain two or more adsorption towers, one of which may be regenerated while the others are still in use. Bed regeneration is achieved by forcing heated regeneration gas upward, allowing pollutants adsorbing at the entrance to be flushed out without having to flush the whole bed. To achieve successful mercury removal and a long, dependable bed life, the beds must be protected against liquid water contamination.

Nitrogen Removal[5]

Nitrogen Rejection's goal is to eliminate nitrogen from feed residue gas to provide a treated stream with low nitrogen content and a better lower heating value (LHV) specification. The nitrogen content in the feed gas stream has a big impact on the best Nitrogen Rejection procedure. There are three main methods used for nitrogen rejection:

  • Cryogenic Distillation
  • Adsorption
  • Membrane Separation

Cryogenic Distillation

Cryogenic distillation is most used technique for nitrogen recovery from gas. A single-column design can be employed for feed concentrations of less than 20% N2. A dual column is preferable for higher concentrations. It can be utilized at lower N2 concentrations with the addition of a recycle compressor. The two-column NRU receives feed containing 15% N2 from a demethanizer. The gas from the overhead demethanizer is cooled by heat exchange and pressure reduction before being put into a 200 psig distillation column (14 barg). The stream is cooled to 240°F (151°C) by reducing the pressure of the bottom product from this high-pressure column. This stream, along with the bottom product from the second low-pressure column, is sent to a heat exchanger at the top of the high-pressure column, which provides the required reflux. The overhead from the high-pressure column passes through three heat exchangers, where it is reduced in pressure to about 15 psig (1 barg) before entering the low-pressure column at 300°F (184°C). This column has a 98 percent N2 overhead and a 98 percent CH4 bottoms product.


Generally, there are two types of adsorption. One is pressure swing adsorption (PSA) and another one is thermal swing adsorption (TSA). TSA is commonly employed in natural gas systems when adsorption is utilized to remove a very small amount of material to a very low level or when the heat of adsorption is very high. PSA may be the best choice for bulk separation of one component from another because the adsorbate concentrations are large, and the adsorption heat is low. Adsorption separation is facilitated by differences in adsorbate polarity and size. The amount of adsorption is determined by four factors such as adsorbent, adsorbate, temperature, and partial pressure of adsorbate.

To separate a binary combination of chemicals A and B, a two-bed PSA system is shown in the diagram. Assume that A is more adsorbed in comparison to B. At room temperature and high pressure, the feed enters the adsorbing bed. The adsorbed phase is enriched in A, and the A content of the gas exiting the bed is reduced, because A is more strongly adsorbed than B. When bed breakthrough causes the outlet concentration of A to rise, it is switched to regeneration mode, and the feed is shifted to the previously regenerated bed to complete the cycle. Regeneration is achieved by lowering the bed pressure, causing the gas to desorb, and then purging the bed to remove the desorbed gas. The adsorption isotherm in figure shows that at a partial pressure, the ultimate concentration of A on the regenerated bed reduces to what will be in equilibrium with the purge gas A. As a result, the entire A cannot be removed from the bed. When the bed is put back into adsorption duty, the residual A is in equilibrium. This means that during the adsorption mode, the gas leaving the bed has a partial pressure. If there is no A in the purge gas, the partial pressure is decreased to zero, and the adsorbed A is desorbed and purged. As a result, the bed can reduce the amount of A in the product to a very low level. For nitrogen rejection, a PSA unit employs a specially treated carbon molecular sieve (CMS). The CMS is made from coal or wood carbon that has been processed. The original article has all the details as well as an economic analysis.

Nitrogen Recovery for Enhanced Oil Recovery[6]

Figure is a general schematic of the operation, which consists of three separate units:

• An air separation plant to generate nitrogen

• A gas plant to recover liquids from the produced stream

• An NRU to produce a sales gas

The reservoir solution gas is handled in a typical gas processing facility to create a heavier hydrocarbon product and a residue gas that is sent to the NRU. For separation, the NRU employs double-column cryogenic distillation. The generated gas contains very little N2 at the start of the process, but the concentration steadily rises as the process progresses. N2 extracted in the NRU is recompressed and injected back into the reservoir in the latter stages of the process. The use of N2 from the air separation plant is reduced as a result of this procedure.     

NGL Extraction Methods

Lean Oil Absorption

Turbo Expander Process


  1. Kutsher, G.S., and Smith, G.A., “CO2 Removal and Recovery Pegasol: A Solvent Process.” Paper presented at the Laurence Reid Gas Conditioning Conference, Norman, OK (1966).
  2. Engineering Data Book, 12th ed., Sec. 22, Sulfur Recovery, Gas Processors Supply Association, Tulsa, OK, 2004.
  3. Lagas, J.A., Borsboom, J., and Heijkoop, G., Claus process gets extra boost, Hydrocarbon Process., 68 (4) 40, 1989.
  4. Campbell, J.M., “Gas Conditioning and Processing,” 7th Ed. Campbell Petroleum Series, Norman, OK (1992).
  5. Goethe, A. and. Mawer, D.J, A New Integrated Nitrogen Rejection Process with NGL Association, Tulsa, OK, 1987, 89.
  6. Alvarez, M.A. and Vines, H.L., Nitrogen rejection/NGL recovery for EOR projects, Energy Prog., 5 (2) 67 1985.

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See also

PEH:Gas Treating and Processing

Dehydration with deliquescing dessicants

Dehydration with glycol

Dehydration with refrigeration and hydrate suppression

Dry dessicant dehydration

Sour gas sweetening