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Process for optimizing removal of condensable components from a fluid

Title: Process for optimizing removal of condensable components from a fluid.
Abstract: A method for removing condensable components from a fluid containing condensable components. The method involves optimizing the temperature of an initial feed stream including the condensable components through heat exchange and cooling to condense liquids there from. The liquids are removed to form a gas stream which is then compressed and after-cooled to form a high pressure stream. A portion of the high pressure stream is expanded to form a cooled low pressure stream which is mixed with the initial feed stream to augment cooling and condensation of condensable components in the initial feed stream. ...
USPTO Applicaton #: #20140075985
Inventors: N. Wayne Mckay, James Maddocks

The Patent Description & Claims data below is from USPTO Patent Application 20140075985, Process for optimizing removal of condensable components from a fluid.


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The present invention relates to the removal of condensables from fluid mixtures exhibiting a positive Joule-Thomson effect, and more particularly the present invention relates to the removal of, for example, water from acid gas streams, for minimizing or substantially eliminating the formation of liquid water therein so as to minimize corrosion and formation of hydrates in the gas stream, transported and injected for sequestration. A discussion of retrofit and enhanced hydrocarbon recovery is also provided.


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Gas streams, such as those which result from petroleum processing or combustion processes, often contain a gas or gases which form an acid when mixed with water. Such gases are typically called “acid gases”. The most common naturally occurring acid gases resulting from petroleum processing are hydrogen sulfide (H2S) and carbon dioxide (CO2). Typical acid gases derived from combustion/oxidation/pyrolysis processes are carbon dioxide (CO2), sulphur dioxide (SO2), and nitrogen oxides (NO, NO2).

Acid gases typically contain water. Naturally occurring acid gases are often saturated with water in the reservoir and combustion-derived gases co-exist with the water formed from the reaction of hydrogen and oxygen during combustion. Virtually all acid gases eventually end up being saturated with water vapour at some point during the process of removal or purification of the acid gas. Reducing the temperature or increasing the pressure, over a defined range, of an acid gas containing water, such as that which occurs when the acid gas is passed through a compressor, will result in the condensing of some of the water from a gas to a liquid phase. At some temperature, still above the freezing point of water, the water and acid gas may begin to form a “solid like” structure called a gas hydrate. The temperature at which hydrates may begin to form is called the Hydrate Formation Temperature (HFT) which varies according to the pressure, composition and water content of the mixture. Hydrates are the physical combination of water and small molecules producing a compound having an “ice like” appearance, but possessing different properties and structure than ice. Hydrates may also be known as gas clathrate. Hydrates are problematic as they can cause reduced heat transfer, excess pressure drops, blockages, interruptions in production and are a safety concern.

The formation of an aqueous phase in any gas system is undesirable as it promotes corrosion, can cause gas hydrates to form and can cause mechanical and operational problems. An aqueous phase is particularly undesirable in an acid gas system as the resulting aqueous phase will be acidic, resulting in a significant increase in the corrosion rate and usually resulting in a higher HFT than non-acid gases.

Table A illustrates the levels of corrosion which occur in mild steel at varying concentrations of acid gas components in water.

TABLE A Corrosion of Mild Steel by Carbon Dioxide and Other Gases in Water* H2S conc. Corrosion mils/yr CO2 Corrosion mils/yr 02 conc. ppm ppm conc, 200 ppm CO2 conc, 600 ppm 8.8 0 28 60 4.3 0 18 44 1.6 0 12 34 0.4 0 17 27 <0.5 35 6 6 <0.5 150 15 16 <0.5 400 17 21

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stats Patent Info
Application #
US 20140075985 A1
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