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Difference between revisions of "Gas treating and processing"

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(Condensate and oil removal, mercury removal)
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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.
 
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.
 
 
==Sour gas sweetening==
 
==Sour gas sweetening==
  
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*[[Dehydration_with_refrigeration_and_hydrate_suppression|and refrigeration and hydrate suppression with a chemical]]
 
*[[Dehydration_with_refrigeration_and_hydrate_suppression|and refrigeration and hydrate suppression with a chemical]]
  
==Mercury Removal==
+
==Nitrogen Removal==
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 ==
 
  
 
==References==
 
==References==

Revision as of 11:24, 22 November 2021

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:

Nitrogen Removal

References

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Noteworthy papers in OnePetro

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External links

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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