Acid gas removal from various gas streams, and especially removal of carbon dioxide from natural gas streams has become an increasingly important process as the acid gas content of various gas sources is relatively high, or increases over time. For example, various natural gas sources in Alaska, continental North America, Norway, Southeast Asia, or in the gulf of Mexico contain carbon dioxide ranging from about 20% to about 75%. Furthermore, acid gas from various gas fields also contains hydrogen sulfide at significant concentrations that typically needs to be removed to meet pipeline quality specifications.
For example, in one commonly employed process for acid gas removal, a chemical solvent (e.g., an amine solvent) is used for acid gas removal, which typically requires additional processing of the isolated acid gas in a sulfur plant to convert the hydrogen sulfide from the regenerated solvent into sulfur as a byproduct. Such acid gas removal and sulfur plant combinations are generally energy intensive and costly. Moreover, in today's diminishing sulfur market the so produced sulfur is only of little commercial value and is consequently disposed of, which still further increases cost for such operations.
Alternatively, membrane systems may be employed to physically separate the acid gas from a gaseous feed stream. Membrane systems are often highly adaptable to accommodate treatment of various gas volumes and product-gas specifications. Furthermore, membrane systems are relatively compact and are generally free of moving parts, therefore rendering such systems an especially viable option for offshore gas treatment. However, all or almost all single stage membrane separators are relatively non-selective and therefore produce a carbon dioxide permeate stream with a relatively high methane and hydrocarbon content (which is either vented, incinerated, or used as a low BTU fuel gas). Consequently, the relatively high methane and hydrocarbon losses often render the use of this process undesirable and uneconomical. To reduce such losses, multiple stages of membrane separators with inter-stage recompression may be used. However, such systems are often energy intensive and costly.
In yet another example, a physical solvent is employed for removal of acid gas from a feed gas, which is particularly advantageous for treating gas with a high acid gas partial pressure as the potential treating capacity of the physical solvent increases with the acid gas partial pressure (Henry's law). Using physical solvents, absorption of a particular acid gas predominantly depends upon the particular solvent employed, and is further dependent on pressure and temperature of the solvent. For example, methanol may be employed as a low-boiling organic physical solvent, as exemplified in U.S. Pat. No. 2,863,527 to Herbert et al. However, the refrigerant cooling requirement to maintain the solvent at cryogenic temperatures is relatively high, and the process often exhibits greater than desired methane and ethane absorption, thereby necessitating large energy input for recompression and recovery.
A typical physical solvent process is exemplified in Prior Art FIG. 1, which is conceptually relatively simple and employs use of a cold lean solvent to remove carbon dioxide from the feed gas. The solvent is regenerated by successive flashing to lower pressures and the flashed solvent is then pumped to the absorber, wherein the solvent is cooled using external refrigeration (either in the rich solvent or the lean solvent circuit). In most instances, a steam or fuel fired heater is required for solvent regeneration.
Physical solvent processes are generally advantageous for bulk acid gas removal (e.g., the treated gas has 1 to 2% remaining acid gas). However, it is often difficult to remove sour gases, and particularly hydrogen sulfide, to levels that meet pipeline gas quality. Moreover, typical conventional processes require regeneration of the solvent with heat or steam, which tends to be relatively energy intensive. Without application of heat for solvent regeneration, currently known flash regeneration processes will not produce a sufficiently lean solvent for gas treating to meet the pipeline specification for hydrogen sulfide.
Thus, although various configurations and methods are known to remove acid gases from a feed gas, all or almost all of them suffer from one or more disadvantages. Among other things, hydrogen sulfide levels in the treated gases are often unacceptably high for current standards, and without further processing, the treated gas can often not meet the pipeline specifications. Furthermore, known processes tend to require substantial amounts of energy to reduce the acid gas concentration to pipeline standards and incur significant hydrocarbon losses. Therefore, there is still a need to provide improved methods and configurations for acid gas removal.
USPTO Backgrounds
USPTO Backgrounds