207 results about "Carbon dioxide removal" patented technology

A power plant including an air separation unit (ASU) arranged to separate nitrogen, oxygen, carbon dioxide and argon from air and produce a stream of substantially pure liquid oxygen, nitrogen, carbon dioxide and argon; a steam generator, fired or unfired, arranged to combust a fuel, e.g., natural gas, liquefied natural gas, synthesis gas, coal, petroleum coke, biomass, municipal solid waste or any other gaseous, liquid or solid fuel in the presence of air and a quantity of substantially pure oxygen gas to produce an exhaust gas comprising water, carbon dioxide, carbon monoxide, nitrogen oxides, nitrogen, sulfur oxides and other trace gases, and a steam-turbine-generator to produce electricity, a primary gas heat exchanger unit for particulate/acid gas/moisture removal and a secondary heat exchanger arranged to cool the remainder of the exhaust gases from the steam generator. Exhaust gases are liquefied in the ASU thereby recovering carbon dioxide, nitrogen oxides, nitrogen, sulfur oxides, oxygen, and all other trace gases from the steam generator exhaust gas stream. The cooled gases are liquefied in the ASU and separated for sale or re-use in the power plant. Carbon dioxide liquid is transported from the plant for use in enhanced oil recovery or for other commercial use. Carbon dioxide removal is accomplished in the ASU by cryogenic separation of the gases, after directing the stream of liquid nitrogen from the air separation unit to the exhaust gas heat exchanger units to cool all of the exhaust gases including carbon dioxide, carbon monoxide, nitrogen oxides, nitrogen, oxygen, sulfur oxides, and other trace gases.

A process for efficiently removing carbon dioxide from a hydrocarbon containing feed stream utilizing a membrane separation unit in conjunction with a heat exchanger and a carbon dioxide separation unit wherein the streams obtained in the carbon dioxide separation unit are utilized to provide the cooling effect in the heat exchanger.

A method and system for storing and supplying hydrogen to a hydrogen pipeline in which a compressed hydrogen feed stream is introduced into a salt cavern for storage and a stored hydrogen stream is retrieved from the salt cavern and reintroduced into the hydrogen pipeline. A minimum quantity of stored hydrogen is maintained in the salt cavern to produce a stagnant layer having a carbon dioxide content along the cavern wall and the top of a residual brine layer located within the salt cavern. The compressed hydrogen feed stream is introduced into the salt cavern and the stored hydrogen stream is withdrawn without disturbing the stagnant layer to prevent carbon dioxide contamination from being drawn into the stored hydrogen stream being reintroduced into the hydrogen pipeline. This allows the stored hydrogen stream to be reintroduced into the hydrogen pipeline without carbon dioxide removal.

The invention pertains to a lean process for the production of hydrocarbons in which a tail gas is subjected to shift conversion, carbon dioxide removal, and then to purification in a PSA to obtain a hydrogen stream comprising more than 99 vol % hydrogen. The Fischer Tropsch process is a single-stage process. The hydrogen stream can be used to upgrade the Fischer-Tropsch hydrocarbons.

Apparatus and methods for removing carbon dioxide from whole blood. Hydrogen ions are generated from water in the blood, resulting in the formation and release of carbon dioxide from the blood.

A process for removal of carbon dioxide from air using lithium-exchanged X-zeolites at low carbon dioxide partial pressures is provided. The process is particularly useful in applications where fresh air is not available and exhaled air needs to be recycled. An apparatus for carrying out the process is also provided.

Process for the production of substitute natural gas (SNG) by the methanation of a synthesis gas derived from the gasification of a carbonaceous material together with water gas shift and carbon dioxide removal thereby producing a synthesis gas with a molar ratio (H₂—CO₂)/(CO+CO₂) greater than 3.00. At the same time, a gas with a molar ratio (H₂—CO₂)/(CO+CO₂) lower than 3.00 is added to the methanation section. The final product (SNG) is of constant high quality without excess of carbon dioxide and hydrogen.

A fuel cell system comprises a fuel cell assembly, a carbon-dioxide-removal unit, an anode exhaust conduit connecting the fuel cell assembly and the carbon-dioxide-removal unit, a fuel source, an oxygen source, a fuel conduit connecting, at least in part, the fuel source with the fuel cell assembly, and a recycle conduit connecting the carbon-dioxide-removal unit with at least one of the fuel cell assembly, the fuel conduit and the fuel source. The fuel cell assembly includes at least one fuel cell, each fuel cell including an anode and a cathode. The carbon-dioxide-removal unit removes carbon dioxide that is in a gas phase. The carbon-dioxide-removal unit includes a carbon-dioxide-removing material. The fuel source and the oxygen source are each independently in fluid communication with the fuel cell assembly. The fuel conduit and the recycle conduit are optionally merged into a single recycle-fuel conduit that extends to the fuel cell assembly. The recycle conduit and/or the recycle-fuel conduit directs essentially all gaseous fluid from the carbon-dioxide-removal unit to the fuel cell assembly.

A method for converting a raw gas into a methane-rich and/or hydrogen-rich gas includes the following steps: a) providing the raw gas stemming from a coal and/or biomass gasification process, thereby the raw gas comprising beside a methane and hydrogen content carbon monoxide, carbon dioxide, alkanes, alkenes, alkynes, tar, especially benzole and naphthalene, COS, hydrogen sulfide and organic sulfur compounds, especially thiophenes; thereby the ratio of hydrogen to carbon monoxide ranges from 0.3 to 4; b) bringing this raw gas into contact with a catalyst in a fluidized bed reactor at temperatures above 200° C. and at pressures equal or greater than 1 bar in order to convert the raw gas into a first product gas, thereby simultaneously converting organic sulfur components into hydrogen sulfide, reform tars, generate water/gas shift reaction and generate methane from the hydrogen/carbon monoxide content; c) bringing the first product gas into a sulfur absorption process to generate a second product gas, thereby reducing the content of hydrogen sulfur and COS from 100 to 1000 ppm down to 1000 ppb or less; d) optionally bringing the second product gas into a carbon dioxide removal process to generate a third product gas at least almost free of carbon dioxide; e) bringing the third product gas into a second methanation process to generate a fourth product gas having a methane content above 5 vol %; f) optionally bringing the fourth product gas into a carbon dioxide removal process to generate a fifth product gas at least almost free of carbon dioxide g) bringing the fifth product gas into an hydrogen separation process in order to separate a hydrogen rich gas from a remaining methane-rich gas, called substitute natural gas.

A low carbon emissions, combined cycle power plant utilizes vortex nozzles (38) operative at cryogenic temperatures to separate out carbon dioxide (39) from the flue gases. Complexity of the plant is minimized by operating a gas turbine engine component (10) of the plant at a turbine exhaust pressure of at least 2 bar, so that downstream components of the plant, including a heat recovery steam generator (19A), a gas cooling system (30, 33, 36), and the inlets of the vortex nozzles, all operate at the same pressure of at least two bar. To increase carbon dioxide concentration in the flue gases (37) that pass through the vortex nozzles (38), and thereby increase efficiency of carbon dioxide removal from the flue gases, up to 50% of the flue gases that exit the heat recovery steam generator (19A) may be recirculated to a location (L, FIG. 4)) in the compressor of the gas turbine engine where the pressure of the compressor air matches the flue gas pressure.

In one embodiment, a power system comprises: a first compressor unit, a syngas generator in fluid communication with a fuel stream and the first compressor unit, a syngas expander unit configured to directly receive the first syngas stream from the syngas generator, a first steam generator, a water gas shift reactor, and a carbon dioxide removal unit. The first compressor unit is configured to compress an air stream and form a first pressurized stream, while the syngas generator is configured to generate a first syngas stream. The syngas expander is configured to reduce the pressure of the first syngas stream. The first steam generator is configured to cool the second syngas stream. The carbon dioxide removal unit configured to remove carbon dioxide from the converted syngas stream.

A system and method for producing electricity is described. The system comprises a fuel cell assembly. The system may comprise a steam turbine and a generator. The fuel cell assembly may be used to provide heat to produce the steam used to power the steam turbine. The system may comprise a gasifier that is operable to produce a fuel for use in the fuel cell assembly. The system may comprise an air separation unit that is operable to supply oxygen to the gasifier and to the fuel cell assembly for reaction with the fuel. The oxygen that is not reacted in the fuel cell assembly may be recirculated through the fuel cell assembly. Spent fuel from the fuel cell assembly may be recirculated through the fuel cell assembly. A carbon dioxide removal system may be used to remove carbon dioxide from the fuel upstream of the fuel cell.

A process involving membrane-based gas separation and power generation, specifically for controlling carbon dioxide emissions from gas-fired power plants. The process includes a compression step, a combustion step, and an expansion/electricity generation step, as in traditional power plants. The process also includes a sweep-driven membrane separation step and a carbon dioxide removal or capture step. The carbon dioxide removal step is carried out on a portion of gas from the compression step.

A carbon dioxide absorbent is disclosed. The absorbent compostion contains a liquid, non-aqueous, silicon-based material, functionalized with one or more groups that reversibly react with CO₂ and/or have a high-affinity for CO₂; and at least one amino alcohol compound. A method for reducing the amount of carbon dioxide in a process stream is also described. The method includes the step of contacting the stream with the carbon dioxide absorbent composition. A power plant that includes a carbon dioxide removal unit based on the carbon dioxide absorbent is also described.

A system for removing CO₂ from air such as atmospheric air is described that uses a cooling tower, a pseudo-cooling tower, or a wind capture device to provide a large volume of atmospheric air. A CO₂ capture apparatus is positioned to contact atmospheric air moving towards or within the cooling tower, pseudo-tower, or wind capture device, and includes wherein the CO₂ capture apparatus includes a CO₂ binding agent that binds to CO₂ in atmospheric air. An associated reprocessing apparatus releases C02 from the binding agent, directs the released CO₂ to a CO₂ storage chamber, and returns the binding agent to the CO₂ capture apparatus. A system for removing CO₂ from flue gas is also described.

A swing bed canister assembly for a regenerative carbon dioxide removal system includes a housing that includes an integrally formed central wall that divides an adsorbing amine bed from a desorbing amine bed. The central wall defines spaces for each of the amine beds so that each portion of the desorbing amine bed is disposed in thermal communication with an adsorbing amine bed to facilitate desorption.

The invention relates to a field recovery and purification method for associated gas at a well head, which is used for the field purification and recovery of the associated gas at the well head. The invention solves the problem of difficult recovery of the associated gas at well heads of remote and dispersed oil field, makes full use of energy and reduces environmental pollution. The technical proposal comprises the following steps: inputting the associated gas into a separator to remove tiny solid particles and heavy hydrocarbon emulsion in the associated gas and reclaim condensed oil; then inputting the gas into a gas preheater for heating and reaching the required purification temperature, inputting the gas into a compressor for reaching certain pressure, and inputting the gas into a devulcanizer for removing hydrogen sulfide gas; inputting the devulcanized associated gas into a decarburization tank for removing carbon dioxide; sending the gas into a purification assembly and a deep drain sump for carrying out deep dehydration and carbon dioxide removal through a molecular film; and finally sending the gas into a cold box for decompression and cooling, and preparing the associated gas into liquefied gas which is inputted into a storage tank. The method applicable to oil fields can realize the aims of energy conservation and emission reduction; the method facilitates the skid migration with simple structure and convenient use; and the recovery operation is free of field limitations.