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Search Petrowiki: TEG
...Glossary:TEG Triethylene glycol...
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...Retrieved from "https://petrowiki.org/index.php?title Glossary:TEG&oldid 38767"...
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...y simple compared to glycol systems, capital cost is normally less than that of triethylene glycol (TEG) systems. This is especially true if emission control systems are required with the ...TEG unit. Deliquescing desiccant systems are very simple to operate and require minimal maintenance. Th...ow-temperature gas streams in which small quantities of water vapor exist. Compared to conventional TEG dehydration, more gas can be sold with desiccant dehydration because there is no fuel or pump gas c...
Deliquescing desiccants are salts that adsorb water vapor; the water then condenses and dissolves the salt. The water drops down as brine and is removed from the vessel. In the past, the common deliquescing desiccant was calcium chloride (CaCl2).[1] Deliquescing desiccants have been used to dehydrate natural gas since the early 1920s. Early desiccant systems were plagued with numerous operational problems, such as channeled gas flow and bridging, which caused washouts and velocity problems within the desiccant bed and ultimately resulted in inadequate dehydration of the gas stream.
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...ing the hydrate temperature in refrigeration units. Of the other three glycols, triethylene glycol (TEG) is the most commonly used glycol for dehydration of natural gas because of the advantages relative... to diethylene glycol (DEG): * TEG is more easily regenerated to a higher degree of purity * Vapor losses are lower * Operating cost...re lower * Table 1 Tetraethylene glycol would have to be regenerated at higher temperatures than TEG to reach the required purity for application in a glycol dehydration unit. [2] Thus, of the four gl...
All raw natural gas is fully saturated with water vapor when produced from an underground reservoir. Because most of the water vapor has to be removed from natural gas before it can be commercially marketed, all natural gas is subjected to a dehydration process. One of the most common methods for removing the water from produced gas is glycol. This page discusses the types of glycols that may be used, the process used to remove water with glycol, and the control of air emissions from glycol dehydration units. The water vapor content of natural gas at equilibrium saturation is shown in Figure 1, which is based on the well-known McKetta and Wehe chart and expanded to 400 F on the basis of data of Olds, Sage, and Lacy.[1][2] As can be seen, the water content increases with increasing temperature and decreasing pressure. When natural gas is a feedstock to a turboexpander plant for high natural gas liquids (NGL) recovery, virtually all the water must be removed before chilling the gas to very low temperatures. There are four glycols that are used in removing water vapor from natural gas or in depressing the hydrate formation temperature.Table 1 lists these glycols and shows some of the properties of the pure material.[3] Ethylene glycol (EG) is not used in a conventional glycol dehydrator, as described below. The main use of EG in the dehydration of natural gas is in depressing the hydrate temperature in refrigeration units. Tetraethylene glycol would have to be regenerated at higher temperatures than TEG to reach the required purity for application in a glycol dehydration unit. In glycol dehydration, TEG is usually referred to only as "glycol." Unless otherwise specified, that convention is used in the rest of this page.
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...ing the hydrate temperature in refrigeration units. Of the other three glycols, triethylene glycol (TEG) is the most commonly used glycol for dehydration of natural gas because of the advantages relative... to diethylene glycol (DEG): TEG is more easily regenerated to a higher degree of purity; vapor losses are lower; and operating cost...ower. * Table 5.3 Tetraethylene glycol would have to be regenerated at higher temperatures than TEG to reach the required purity for application in a glycol dehydration unit. [25] Thus, of the four g...
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, it 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. 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, and relative condensate/gas rates; specifications for the residue gas; and rate of gas sales. The end user of natural gas needs to be assured of two conditions before committing to the use of gas in ...
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...RM * Glossary:TDS * Glossary:TDT * Glossary:Technical limit * Glossary:Tectonic map * Glossary:TEG * Glossary:TEL * Glossary:Telemetry * Glossary:Telescoping mast * Glossary:Tell tale * Glossar...
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...ed for reuse in absorbing more water with less glycol. Commonly used glycol for this process is the TEG that is Triethylene Glycol. Soil Bed Dehydration Adsorption is the basis of solid bed dehydration...he free water must be removed and the dew point of the gas decreased before chilling the feed. With TEG, it is feasible to dehydrate the gas. The glycol and water separate in the cold separator and are ...
Oil and gas wells produce a mixture of hydrocarbon gas, condensate or oil; water with dissolved minerals, usually including a large amount of salt; other gases, including nitrogen, carbon dioxide (CO2), and possibly hydrogen sulfide (H2S); and solids, including sand from the reservoir, dirt, scale, and corrosion products from the tubing. The purpose of oil and gas processing is to separate, remove, or transform these various components to make the hydrocarbons ready for sale. A production facility's job is to separate the well stream into three components, commonly referred to as "phases" (oil, gas, and water), and then process or dispose of these phases in an environmentally safe manner. In mechanical devices called "separators" gas is flashed from the liquids and "free water" is separated from the oil. The goal is to produce oil that meets the purchaser's specifications that define the maximum allowable amounts of the following: * Water * Salt * Other impurities Similarly, the gas must be processed to meet purchaser's water vapor and hydrocarbon dewpoint specifications to limit condensation during transportation. Several factors should be considered when selecting a treating system to determine the most desirable method of treating crude oil to pipeline requirements.
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...usually a solution of one of the glycols; generally, diethylene glycol (DEG) or triethylene glycol (TEG) is used. The method of operation is the same for both systems. Surface production facilities Th...
The following topic describes Gas distribution and control, Gas compression and dehydration and Gas surface facilities. Figs. 1 and 2 show the amount of injection gas and compression brake horsepower per well, respectively, required to obtain identical producing rates using several different surface injection-gas pressures. As expected, compression horsepower decreases as injection-gas pressure increases for a given daily liquid rate, until the injection-gas pressure reaches maximum injection depth. An injection-gas pressure greater than that required to inject at maximum depth requires additional compression without additional production. In the example shown in Figs. 1 and 2, a significant decrease in horsepower requirements is possible by employing an injection-gas pressure of 2,000 psig (ANSI Class 900 pipe) rather than one of 1,440 psig (ANSI Class 600 pipe) or lower.
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...er than the top of the fire tube. Fig. 5.12--Equilibrium water dewpoint vs. temperature at various TEG concentrations (after Engineering Data Book of Gas Processors Suppliers Association and Gas Process... not necessarily achieve the desired dehydration of the gas. Fig. 5.13--Effect of stripping gas on TEG concentration (after Engineering Data Book of Gas Processors Suppliers Association and Gas Processo...his temperature, the glycol molecule breaks down. In light of this, the normal temperature in which TEG is heated in the reboiler is about 380 to 390 F. This temperature range results in a lean glycol pu...
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, it 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. 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, and relative condensate/gas rates; specifications for the residue gas; and rate of gas sales. 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; and 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. 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. 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.
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...usually a solution of one of the glycols; generally, diethylene glycol (DEG) or triethylene glycol (TEG) is used. The method of operation is the same for both systems. Surface Production Facilities Th...
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