Gas treating and processing

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.

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

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.

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:

• absorption with glycol
• adsorption with dry desiccant
• absorption with a deliquescent salt
• and refrigeration and hydrate suppression with a chemical

References

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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