Low emission power generation systems and methods incorporating carbon dioxide separation

Abstract

Methods and systems for CO 2 separation in low emission power plants are provided. One system includes a gas turbine system that combusts a fuel and an oxidant in the presence of a compressed recycle stream to provide mechanical power and a gaseous exhaust. A purge stream is taken from the compressed recycle stream and directed to a CO 2 separator configured to absorb CO 2 from the purge stream using a potassium carbonate solvent. Volatiles are removed from the rich solvent by stripping or by flashing to an intermediate pressure before the rich solvent is regenerated and CO 2 is removed.

Claims

What is claimed is: 1. An integrated power generation system, comprising: a gas turbine system comprising a combustion chamber configured to combust a compressed oxidant and a fuel in the presence of a compressed recycle stream to generate a discharge stream that is expanded in an expander, thereby generating a gaseous exhaust stream; an exhaust gas recirculation system comprising a boost compressor and one or more cooling units fluidly coupled to the boost compressor, the boost compressor being configured to receive and increase the pressure of the gaseous exhaust stream and the one or more cooling units being configured to cool the gaseous exhaust stream and provide a cooled recycle gas to a main compressor, wherein the main compressor compresses the cooled recycle gas and generates the compressed recycle stream; a purge stream fluidly coupled to the compressed recycle stream having a heat exchanger configured to reduce the temperature of the purge stream and generate a cooled purge stream; and a CO 2 separation system fluidly coupled to the heat exchanger, the CO 2 separation system comprising: an absorption column configured to receive the cooled purge stream and absorb CO 2 from the cooled purge stream with a potassium carbonate solvent to generate a nitrogen-rich residual stream and a bicarbonate solvent solution; a first valve fluidly coupled to the absorption column configured to flash the bicarbonate solvent solution to a pressure sufficient to separate volatile components from the bicarbonate solvent solution, thereby generating a dual phase reduced-pressure solvent solution having a gaseous phase comprising the volatile components and a liquid phase comprising the bicarbonate solvent solution; a flash vessel fluidly coupled to the first valve configured to receive the reduced-pressure solvent solution and remove the gaseous phase of the reduced-pressure solvent solution from the liquid phase of the reduced-pressure solvent solution, wherein at least a portion of the gaseous phase of the reduced-pressure solution removed from the flash vessel is recycled to the exhaust gas recirculation system; a second valve fluidly coupled to the flash vessel configured to receive the liquid phase of the reduced-pressure solvent solution and flash the liquid phase to a near-atmospheric pressure, thereby generating a near-atmospheric bicarbonate solvent solution; and a regeneration column fluidly coupled to the second valve configured to receive and boil the near-atmospheric bicarbonate solvent solution to remove CO 2 and water therefrom, producing a regenerated potassium carbonate solvent to be recycled to the absorption column. 2. The system of claim 1 , wherein the first valve is configured to flash the bicarbonate solvent solution to a pressure such that the gaseous phase of the bicarbonate solvent solution comprises less than 1.0 mol % carbon dioxide. 3. The system of claim 2 , wherein the first valve is configured to flash the bicarbonate solvent solution to a pressure such that at least 98 mol % of the total carbon dioxide in the bicarbonate solvent solution remains in the liquid phase of the reduced-pressure solvent solution. 4. The system of claim 1 , further comprising a reboiler fluidly coupled to the regeneration column and configured to receive and heat a portion of the regenerated potassium carbonate solvent and produce a heated regenerated potassium carbonate solvent. 5. The system of claim 4 , wherein the reboiler is configured to recycle the heated regenerated potassium carbonate solvent to the regeneration column to produce steam. 6. The system of claim 1 , further comprising a condenser fluidly coupled to the regeneration column configured to receive the CO 2 and water removed from the bicarbonate solvent solution and separate the water from the CO 2 . 7. The system of claim 6 , wherein a portion of the water separated from the CO 2 is pumped back to the regeneration column to create steam. 8. The system of claim 1 , wherein the at least a portion of the gaseous phase of the reduced-pressure solution recycled to the exhaust gas recirculation system is combined with the cooled recycle gas provided to the main compressor. 9. The system of claim 1 , wherein the combustion chamber is configured to stoichiometrically combust the compressed oxidant and the fuel in the presence of the compressed recycle stream. 10. The system of claim 1 , wherein the compressed recycle stream acts as a diluent configured to moderate the temperature of the discharge stream. 11. The system of claim 1 , wherein one or both of the first and second valves is a hydraulic turbine configured to generate power. 12. A method for generating power, comprising: combusting a compressed oxidant and a fuel in a combustion chamber and in the presence of a compressed recycle stream, thereby generating a discharge stream, and expanding the discharge stream to generate a gaseous exhaust stream; increasing the pressure of the gaseous exhaust stream and cooling the gaseous exhaust stream to generate a cooled recycle gas that is compressed to generate the compressed recycle stream; cooling a purge stream fluidly coupled to the compressed recycle stream to generate a cooled purge stream; directing the cooled purge stream to an absorption column and absorbing CO 2 from the cooled purge stream with a potassium carbonate solvent; discharging a nitrogen-rich residual stream and a bicarbonate solvent solution from the absorption column; flashing the bicarbonate solvent solution to a pressure sufficient to separate volatile components from the bicarbonate solvent solution, generating a dual phase reduced-pressure solvent solution having a gaseous phase comprising the volatile components and a liquid phase comprising the bicarbonate solvent solution; separating the gaseous phase of the reduced-pressure solvent solution from the liquid phase of the reduced-pressure solution, wherein at least a portion of the gaseous phase of the reduced-pressure solvent solution is recycled and combined with the cooled recycle gas; flashing the liquid phase of the reduced-pressure solvent solution to a near-atmospheric pressure to generate a near-atmospheric solvent solution; boiling the near-atmospheric solvent solution in a regeneration column to remove CO 2 and water therefrom, thereby generating a regenerated potassium carbonate solvent; and recycling the regenerated potassium carbonate solvent to the absorption column. 13. The method of claim 12 , wherein the bicarbonate solution is flashed to a pressure such that the gaseous phase of the reduced-pressure solvent solution comprises less than 1.0 mol % CO 2 . 14. The method of claim 13 , wherein the bicarbonate solution is flashed to a pressure such that at least 98 mol % of the total CO 2 in the bicarbonate solvent solution remains in the liquid phase of the reduced-pressure solvent solution. 15. The method of claim 12 , further comprising receiving the CO 2 and water removed from the near-atmospheric solvent solution in a condenser fluidly coupled to the regeneration column and separating the water from the CO 2 . 16. The method of claim 15 , wherein a portion of the water separated from the CO 2 in the condenser is directed to the regeneration column to create steam. 17. The method of claim 12 , wherein the compressed oxidant and the fuel are combusted in the presence of the compressed recycle stream under stoichiometric conditions. 18. The method of claim 12 , wherein the compressed recycle stream moderates the temperature of the discharge stream. 19. An integrated power generation system, comprising: a gas turbine system comprising a combustion chamber configured to combust a compressed oxidant and a fuel in the presence of a compressed recycle stream to generate a discharge stream that is expanded in an expander, thereby generating a gaseous exhaust stream; an exhaust gas recirculation system comprising a boost compressor and one or more cooling units fluidly coupled to the boost compressor, the boost compressor being configured to receive and increase the pressure of the gaseous exhaust stream and the one or more cooling units being configured to cool the gaseous exhaust stream and provide a cooled recycle gas to a main compressor, wherein the main compressor compresses the cooled recycle gas and generates the compressed recycle stream; a purge stream fluidly coupled to the compressed recycle stream having a heat exchanger configured to reduce the temperature of the purge stream and generate a cooled purge stream; and a CO 2 separation system fluidly coupled to the heat exchanger, the CO 2 separation system comprising: an absorption column configured to receive the cooled purge stream and absorb CO 2 from the cooled purge stream with a potassium carbonate solvent to generate a nitrogen-rich residual stream and a bicarbonate solvent solution; a first valve fluidly coupled to the absorption column configured to flash the bicarbonate solvent solution to a pressure sufficient to separate volatile components from the bicarbonate solvent solution and such that the gaseous phase of the bicarbonate solvent solution comprises less than 1.0 mol % carbon dioxide, thereby generating a dual phase reduced-pressure solvent solution having a gaseous phase comprising the volatile components and a liquid phase comprising the bicarbonate solvent solution; a flash vessel fluidly coupled to the first valve configured to receive the reduced-pressure solvent solution and remove the gaseous phase of the reduced-pressure solvent solution from the liquid phase of the reduced-pressure solvent solution; a second valve fluidly coupled to the flash vessel configured to receive the liquid phase of the reduced-pressure solvent solution and flash the liquid phase to a near-atmospheric pressure, thereby generating a near-atmospheric bicarbonate solvent solution; and a regeneration column fluidly coupled to the second valve configured to receive and boil the near-atmospheric bicarbonate solvent solution to remove CO 2 and water therefrom, producing a regenerated potassium carbonate solvent to be recycled to the absorption column. 20. The system of claim 19 , wherein the first valve is configured to flash the bicarbonate solvent solution to a pressure such that at least 98 mol % of the total carbon dioxide in the bicarbonate solvent solution remains in the liquid phase of the reduced-pressure solvent solution. 21. The system of claim 19 , further comprising a reboiler fluidly coupled to the regeneration column and configured to receive and heat a portion of the regenerated potassium carbonate solvent and produce a heated regenerated potassium carbonate solvent. 22. The system of claim 21 , wherein the reboiler is configured to recycle the heated regenerated potassium carbonate solvent to the regeneration column to produce steam. 23. The system of claim 19 , further comprising a condenser fluidly coupled to the regeneration column configured to receive the CO 2 and water removed from the bicarbonate solvent solution and separate the water from the CO 2 . 24. The system of claim 23 , wherein a portion of the water separated from the CO 2 is pumped back to the regeneration column to create steam. 25. The system of claim 19 , wherein the at least a portion of the gaseous phase of the reduced-pressure solution recycled to the exhaust gas recirculation system is combined with the cooled recycle gas provided to the main compressor. 26. The system of claim 19 , wherein the combustion chamber is configured to stoichiometrically combust the compressed oxidant and the fuel in the presence of the compressed recycle stream. 27. The system of claim 19 , wherein the compressed recycle stream acts as a diluent configured to moderate the temperature of the discharge stream. 28. The system of claim 19 , wherein one or both of the first and second valves is a hydraulic turbine configured to generate power. 29. A method for generating power, comprising: combusting a compressed oxidant and a fuel in a combustion chamber and in the presence of a compressed recycle stream, thereby generating a discharge stream, and expanding the discharge stream to generate a gaseous exhaust stream; increasing the pressure of the gaseous exhaust stream and cooling the gaseous exhaust stream to generate a cooled recycle gas that is compressed to generate the compressed recycle stream; cooling a purge stream fluidly coupled to the compressed recycle stream to generate a cooled purge stream; directing the cooled purge stream to an absorption column and absorbing CO 2 from the cooled purge stream with a potassium carbonate solvent; discharging a nitrogen-rich residual stream and a bicarbonate solvent solution from the absorption column; flashing the bicarbonate solvent solution to a pressure sufficient to separate volatile components from the bicarbonate solvent solution and to a pressure such that the gaseous phase of the reduced-pressure solvent solution comprises less than 1.0 mol % CO 2 , generating a dual phase reduced-pressure solvent solution having a gaseous phase comprising the volatile components and a liquid phase comprising the bicarbonate solvent solution; separating the gaseous phase of the reduced-pressure solvent solution from the liquid phase of the reduced-pressure solution, wherein at least a portion of the gaseous phase of the reduced-pressure solvent solution is recycled and combined with the cooled recycle gas; flashing the liquid phase of the reduced-pressure solvent solution to a near-atmospheric pressure to generate a near-atmospheric solvent solution; boiling the near-atmospheric solvent solution in a regeneration column to remove CO 2 and water therefrom, thereby generating a regenerated potassium carbonate solvent; and recycling the regenerated potassium carbonate solvent to the absorption column. 30. The method of claim 29 , wherein the bicarbonate solution is flashed to a pressure such that at least 98 mol % of the total CO 2 in the bicarbonate solvent solution remains in the liquid phase of the reduced-pressure solvent solution. 31. The method of claim 29 , further comprising receiving the CO 2 and water removed from the near-atmospheric solvent solution in a condenser fluidly coupled to the regeneration column and separating the water from the CO 2 . 32. The method of claim 31 , wherein a portion of the water separated from the CO 2 in the condenser is directed to the regeneration column to create steam. 33. The method of claim 29 , wherein the compressed oxidant and the fuel are combusted in the presence of a compressed recycle stream under stoichiometric conditions. 34. The method of claim 29 , wherein the compressed recycle stream moderates the temperature of the discharge stream.
CROSS REFERENCE TO RELATED APPLICATIONS This application is the National Stage entry under 35 U.S.C. 371 of PCT/US2012/027781, that published as WO 2012/128929 and was filed on 5 Mar. 2012 which claims the benefit of U.S. Provisional Application No. 61/542,041, filed on 30 Sep. 2011; U.S. Provisional Application 61/466,384 filed Mar. 22, 2011; U.S. Provisional Application 61/542,030 filed Sep. 30, 2011; U.S. Provisional Application 61/466,385 filed Mar. 22, 2011; U.S. Provisional Application 61/542,031 filed Sep. 30, 2011; U.S. Provisional Application 61/466,381 filed Mar. 22, 2011; and U.S. Provisional Application 61/542,035 filed Sep. 30, 2011, each of which is incorporated by reference, in its entirety, for all purposes. This application contains subject matter related to U.S. Provisional Application 61/542,037 filed Sep. 30, 2011 (PCT/US2012/027776, that published as WO 2012/128927 and was filed on 5 Mar. 2012); U.S. Provisional Application 61/542,039 filed Sep. 30, 2011 (PCT/US2012/027780, that published as WO 2012/128928 and was filed on 5 Mar. 2012); and U.S. Provisional Application 61/542,036 filed Sep. 30, 2011 (PCT/US2012/027774, that published as WO 2012/128926 and was filed on 5 Mar. 2012). FIELD OF THE DISCLOSURE Embodiments of the disclosure relate to low emission power generation systems. More particularly, embodiments of the disclosure relate to methods and apparatus for combusting a fuel for power generation and enhanced carbon dioxide (CO 2 ) manufacture, and employing solvent technology to capture the CO 2 . BACKGROUND OF THE DISCLOSURE This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art. Many oil producing countries are experiencing strong domestic growth in power demand and have an interest in enhanced oil recovery (EOR) to improve oil recovery from their reservoirs. Two common EOR techniques include nitrogen (N 2 ) injection for reservoir pressure maintenance and carbon dioxide (CO 2 ) injection for miscible flooding for EOR. There is also a global concern regarding green house gas (GHG) emissions. This concern combined with the implementation of cap-and-trade policies in many countries makes reducing CO 2 emissions a priority for these and other countries as well as the companies that operate hydrocarbon production systems therein. Some approaches to lower CO 2 emissions include fuel de-carbonization or post-combustion capture using solvents, such as amines. However, both of these solutions are expensive and reduce power generation efficiency, resulting in lower power production, increased fuel demand and increased cost of electricity to meet domestic power demand. In particular, the presence of oxygen, sulfur oxides (SO X ), and nitrogen oxide (NO X ) makes the use of amine solvent absorption very problematic. Another approach is an oxyfuel gas turbine in a combined cycle (e.g., where exhaust heat from the gas turbine Brayton cycle is captured to make steam and produce additional power in a Rankine cycle). However, there are no commercially available gas turbines that can operate in such a cycle and the power required to produce high purity oxygen significantly reduces the overall efficiency of the process. Moreover, with the growing concern about global climate change and the impact of CO 2 emissions, emphasis has been placed on minimizing CO 2 emissions from power plants. Gas turbine power plants are efficient and have a lower cost compared to nuclear or coal power generation technologies. Capturing CO 2 from the exhaust of a gas turbine power plant is very expensive, however, because the concentration of CO 2 in the exhaust stack is low, a large volume of gas needs to be treated, and the pressure of the exhaust stream is low. These factors, among others, result in a high cost of CO 2 capture. Capture and recovery of CO 2 from low emission power generation systems that incorporate an exhaust gas recycle loop has been previously described. For example, U.S. Patent Application Ser. No. 61/361,173, which is incorporated herein by reference in its entirety, illustrates the use of a potassium carbonate (K 2 CO 3 ) solvent to absorb and recover CO 2 from such systems. When CO 2 is recovered via solvent absorption, however, the solvent also absorbs small quantities of volatile components (such as, for example, nitrogen, oxygen, argon, and carbon monoxide) that will have a small solubility in a water-based solvent such as K 2 CO 3 . Upon regeneration of the solvent to release the absorbed CO 2 , these volatile components will also be evolved and will remain with the CO 2 . If the CO 2 is used for EOR or is injected into a reservoir for sequestration, the presence of volatiles may be undesirable. For example, the presence of oxygen may increase corrosion rates, while the presence of carbon monoxide (CO) may result in safety or environmental hazards if released during startup or process upset conditions. Accordingly, there is still a substantial need for a low emission, high efficiency power generation process with incorporated CO 2 capture and recovery at a reduced cost. Additionally, when a K 2 CO 3 solvent is employed for CO 2 separation, there is also an interest in removing volatiles from the recovered CO 2 . SUMMARY OF THE DISCLOSURE The present invention is directed to low emission power generation systems that incorporate an exhaust gas recycle loop and carbon dioxide (CO 2 ) capture and recovery using a potassium carbonate-based (K 2 CO 3 ) separation system. In the low emission power generation systems described herein, exhaust gases from low emission gas turbines, which are vented in a typical natural gas combined cycle plant, are instead recycled and a portion of the recycled exhaust gas is separated and recovered. The apparatus, systems, and methods of the invention separate the exhaust gas using a K 2 CO 3 solvent to absorb and recover CO 2 . Such K 2 CO 3 separation processes are sometimes referred to as hot potassium carbonate, or “hot pot” processes. Apparatus and methods for removing volatile components from the CO 2 -rich solvent prior to regeneration of the solvent and removal of CO 2 are further incorporated herein, resulting in the production of high purity CO 2 with little to no contaminants. The recovered CO 2 may be used for enhanced oil recovery (EOR), sequestration, storage, or for a number of other purposes. In the systems and methods of the present invention, fuel and a compressed oxidant are combusted in the presence of a compressed recycle stream in a combustion chamber to generate a discharge stream. The discharge stream is expanded to produce power and generate a gaseous exhaust stream, and the gaseous exhaust stream is cooled and recirculated to the main compressor. The main compressor generates a compressed recycle stream. A portion of the compressed recycle stream is directed back to the combustion chamber to act as a diluent during combustion, while the remainder of the compressed recycle stream is directed to a CO 2 separation system. Within the CO 2 separation system, the exhaust gases are cooled and directed to an absorption column, where a K 2 CO 3 solvent is used to absorb CO 2 from the exhaust gases, generating a nitrogen-rich residual stream and a bicarbonate solvent solution. In one or more embodiments of the invention, volatile components are removed from the bicarbonate solvent solution by stripping the solvent solution with a vapor such as nitrogen, argon, or steam. In other embodiments, volatile components are removed from the bicarbonate solvent solution by flashing the solvent solution to a pressure sufficient to release gaseous volatiles from the solvent while keeping the CO 2 in the liquid solution. The volatile components may then be recycled to the exhaust gas recirculation (EGR) system, such as by combining the volatiles with the cooled recycle stream entering the main compressor. In both scenarios, once volatiles have been removed from the bicarbonate solvent solution, the solution is flashed to atmospheric or near-atmospheric pressure and regenerated by boiling the bicarbonate solvent solution to remove CO 2 and water, producing a lean regenerated K 2 CO 3 solvent. The regenerated solvent may be recycled to the absorption column, while the CO 2 and water removed from the solvent solution may be cooled and condensed to generate a water stream and a recovered CO 2 stream. By removing volatiles from the bicarbonate solvent solution before regenerating the solvent and recovering CO 2 , a higher purity CO 2 product is obtained. BRIEF DESCRIPTION OF THE DRAWINGS The foregoing and other advantages of the present disclosure may become apparent upon reviewing the following detailed description and drawings of non-limiting examples of embodiments in which: FIG. 1 depicts an integrated system for low emission power generation and enhanced CO 2 recovery. FIG. 2 depicts an illustrative CO 2 capture system used in an integrated system for low emission power generation and enhanced CO 2 recovery. FIG. 3 depicts another illustrative CO 2 capture system incorporating a stripping section to remove volatiles prior to regeneration of the bicarbonate solvent solution and removal of CO 2 . FIG. 4 depicts another illustrative CO 2 capture system incorporating a flash step to remove volatiles prior to regeneration of the bicarbonate solvent solution and removal of CO 2 . FIG. 5 depicts an integrated system for low emission power generation and enhanced CO 2 recovery in which volatiles removed in the CO 2 capture system are recycled to the exhaust gas recirculation system. DETAILED DESCRIPTION OF THE DISCLOSURE In the following detailed description section, the specific embodiments of the present disclosure are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present disclosure, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the disclosure is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. Various terms as used herein are defined below. To the extent a term used in a claim is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. As used herein, the term “natural gas” refers to a multi-component gas obtained from a crude oil well (associated gas) or from a subterranean gas-bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (CH 4 ) as a major component, i.e. greater than 50 mol % of the natural gas stream is methane. The natural gas stream can also contain ethane (C 2 H 6 ), higher molecular weight hydrocarbons (e.g., C 3 -C 20 hydrocarbons), one or more acid gases (e.g., hydrogen sulfide, carbon dioxide), or any combination thereof. The natural gas can also contain minor amounts of contaminants such as water, nitrogen, iron sulfide, wax, crude oil, or any combination thereof. As used herein, the term “stoichiometric combustion” refers to a combustion reaction having a volume of reactants comprising a fuel and an oxidizer and a volume of products formed by combusting the reactants where the entire volume of the reactants is used to form the products. As used herein, the term “substantially stoichiometric combustion” refers to a combustion reaction having an equivalence ratio ranging from about 0.9:1 to about 1.1:1, or more preferably from about 0.95:1 to about 1.05:1. As used herein, the term “stream” refers to a volume of fluids, although use of the term stream typically means a moving volume of fluids (e.g., having a velocity or mass flow rate). The term “stream,” however, does not require a velocity, mass flow rate, or a particular type of conduit for enclosing the stream. As used herein, the phrase “near-atmospheric pressure” refers to a pressure within about 10 percent, or preferably within about 5 percent, of the actual atmospheric pressure. For example, if atmospheric pressure is 14.7 psi, any pressure within the range of about 13.2 psi to about 16.2 psi is considered to be “near-atmospheric pressure.” Embodiments of the presently disclosed systems and processes may be used to produce ultra low emission electric power and CO 2 for EOR or sequestration applications. According to some embodiments disclosed herein, a mixture of air and fuel can be combusted and simultaneously mixed with a stream of recycled exhaust gas. The stream of recycled exhaust gas is cooled and compressed and may be used as a diluent to control or otherwise moderate the temperature of the combustion and of the exhaust gas entering the succeeding expander. In one or more embodiments, the combustion conditions are non-stoichiometric. In other embodiments, the combustion conditions are stoichiometric or substantially stoichiometric. The exhaust gases not recycled to the combustion chamber are separated to capture CO 2 and generate a residual stream comprising nitrogen. In EOR applications, the recovered CO 2 is injected into or adjacent to producing oil wells, usually under supercritical conditions. The CO 2 acts as both a pressurizing agent and, when dissolved into the underground crude oil, significantly reduces the oil's viscosity enabling the oil to flow more rapidly through the earth to a removal well. The residual stream comprising nitrogen (and frequently oxygen and argon as well) may be used to generate additional power, and may also be used for a variety of purposes, including for pressure maintenance. In pressure maintenance applications, an inert gas such as nitrogen is compressed and injected into a hydrocarbon reservoir to maintain the original pressure in the reservoir, thus allowing for enhanced recovery of hydrocarbons. The result of the systems disclosed herein is the production of power and the concentration and capture of CO 2 in a more economically efficient manner. Combustion at near stoichiometric conditions (or “slightly rich” combustion) can prove advantageous in order to eliminate the cost of excess oxygen removal. By cooling the exhaust gas and condensing the water out of the stream, a relatively high content CO 2 stream can be produced. While a portion of the recycled exhaust gas can be utilized for temperature moderation in the closed Brayton cycle, a remaining purge stream can be used for EOR applications and electric power can be produced with little or no SO X , NO X , or CO 2 being emitted to the atmosphere. The result of this process is the production of power and the manufacturing of additional CO 2 . Stoichiometric or substantially stoichiometric combustion of the fuel combined with a boost in the pressure of the exhaust gas prior to being compressed for recirculation can make the CO 2 partial pressure much higher than in conventional gas turbine exhaust. As a result, carbon capture in a CO 2 separation process can be undertaken using less energy-intensive solvents, such as potassium carbonate (K 2 CO 3 ). The presence of oxygen (O 2 ), sulfur oxides (SO X ), and nitrogen oxides (NO X ) in the exhaust gas make the use of amine solvents (e.g., MEA, DEA, MDEA, and related solvents) difficult, even with the higher pressure and increased CO 2 content, since amine solvents can degrade in their presence. Moreover, K 2 CO 3 easily absorbs SO X and NO X , converting them to simple fertilizers such as potassium sulfite (K 2 SO 3 ) and potassium nitrate (KNO 3 ). These fertilizers can be easily discharged in an environmentally harmless manner. In one or more embodiments of the present invention, integrated power generation systems are provided comprising a gas turbine system, an exhaust gas recirculation system, and a CO 2 separation system. Various embodiments of each of these components are described in more detail below. Gas Turbine System The gas turbine system comprises a combustion chamber, an inlet compressor, and an expander, where the combustion chamber is configured to combust one or more compressed oxidants and one or more fuels in the presence of a compressed recycle stream to generate a discharge stream. The discharge stream is expanded in an expander to generate a gaseous exhaust stream. The one or more oxidants may comprise any oxygen-containing fluid, such as ambient air, oxygen-enriched air, substantially pure oxygen, or combinations thereof. The one or more fuels may comprise natural gas, associated gas, diesel, fuel oil, gasified coal, coke, naphtha, methane, ethane, butane, propane, syngas, kerosene, aviation fuel, bio-fuel, oxygenated hydrocarbon feedstock, other suitable hydrocarbon containing gases or liquids, hydrogen, carbon monoxide, or combinations thereof. Additionally, the fuel may comprise inert components including but not limited to N 2 or CO 2 . In some embodiments, the fuel may be at least partially supplied by a hydrocarbon reservoir that is benefitting from EOR via injection of CO 2 captured using the process described herein. In certain embodiments, the fuel comprises natural gas. In one or more embodiments, the combustion conditions in the combustion chamber are stoichiometric or substantially stoichiometric. A diluent may be supplied to the combustion chamber to control or otherwise regulate the temperature of the combustion and flue gas to meet the material requirements of the succeeding expander. The flow of the diluent may be adjusted to help maintain stoichiometric conditions in the combustion chamber, moderating changes in composition, volumetric flow, or other variations in the oxidant and fuel streams. In one or more embodiments, the diluent provided to the combustion chamber comprises at least a portion of the compressed recycle stream. In some embodiments, high pressure steam may also be employed as a diluent in the combustion chamber. In such embodiments, the addition of steam would reduce power and size requirements in the system, but would require the addition of a water recycle loop. Additionally, in further embodiments, the compressed oxidant feed to the combustion chamber may comprise argon. For example, the oxidant may comprise from about 0.1 to about 5.0 vol % argon, or from about 1.0 to about 4.5 vol % argon, or from about 2.0 to about 4.0 vol % argon, or from about 2.5 to about 3.5 vol % argon, or about 3.0 vol % argon. The inlet compressor may be a single compressor or two or more compressors operating in parallel or in series. Each compressor may comprise a single stage or multiple stages. In multiple stage compressors, interstage cooling may optionally be employed to allow for higher overall compression ratios and higher overall power output. When more than one compressor is used to compress the oxidant stream, the compressors taken together are considered herein to be the “inlet compressor.” The inlet compressor may be of any type suitable for the process described herein. Such compressors include, but are not limited to, axial, centrifugal, reciprocating, or twin-screw compressors and combinations thereof. In one or more embodiments, the inlet compressor comprises an axial compressor. Combustion of the oxidant and fuel in the combustion chamber generates a discharge stream. The discharge stream comprises products of combustion, and their individual compositions will vary depending upon the composition of the fuel and the oxidant used in the combustion chamber. In one or more embodiments, the discharge stream may comprise vaporized water, CO 2 , O 2 , carbon monoxide (CO), nitrogen (N 2 ), argon (Ar), NO X , SO X , hydrogen sulfide (H 2 S), or combinations thereof. The discharge stream may be expanded in the expander to form a gaseous exhaust stream. The expander may be a single expander or two or more expanders operating in parallel or in series. Each expander may comprise a single stage or multiple stages. When more than one expander is used to expand the discharge stream, the expanders taken together are considered herein to be the “expander.” The expander may be of any type suitable for the process described herein, including but not limited to axial or centrifugal expanders or combinations thereof. Expansion of the discharge stream generates power, which may be used to drive one or more compressors or electric generators. In one or more embodiments of the invention, the expander is coupled to the main compressor, described in further detail below, via a common shaft or other mechanical, electrical, or other power coupling, such that the main compressor is at least partially driven by the expander. In other embodiments, the main compressor may be mechanically coupled to an electric motor with or without a speed increasing or decreasing device such as a gear box. When taken together, the main compressor, combustion chamber, and expander may be characterized as a Brayton cycle. Exhaust Gas Recirculation (EGR) System The exhaust gas recirculation (EGR) system comprises a boost compressor or blower and one or more cooling units fluidly coupled to the boost compressor, where the boost compressor is configured to receive and increase the pressure of the gaseous exhaust stream and the one or more cooling units are configured to cool the gaseous exhaust stream and provide a cooled recycle stream to a main compressor. The main compressor compresses the cooled recycle stream and generates a compressed recycle stream. At least a portion of the compressed recycle stream is directed back to the combustion chamber, while a purge stream comprising another portion of the compressed recycle stream is cooled to generate a cooled purge stream that is directed to the CO 2 separation system. The boost compressor (or blower) and the one or more cooling units may be arranged in any fashion suitable for the intended purpose. For example, the one or more cooling units may be located upstream or downstream of the boost compressor, or may be located both upstream and downstream of the boost compressor. The one or more cooling units may be any type of apparatus suitable for lowering the temperature of the exhaust gases, such as for example a heat recovery unit (HRU), heat exchanger, regenerator, direct contact cooler (DCC), trim cooler, mechanical refrigeration unit, or combinations thereof. In some embodiments, the cooling unit is an HRU, which may be located upstream of the boost compressor. When used, the HRU may be configured to receive the gaseous exhaust stream and utilize the residual heat in the stream to generate steam, such as in a heat recovery steam generator (HRSG). The steam generated by the HRSG may be used for a variety of purposes, such as to drive a steam turbine generator in a Rankine cycle or for water desalination. In the same or other embodiments, the cooling unit is a DCC, which may be located upstream or downstream of the boost compressor. When used, the DCC may be configured to remove a portion of condensed water from the cooled recycle stream via a water dropout stream. In some embodiments, the water dropout stream may optionally be routed to a HRSG to provide a water source for the generation of additional steam. In some embodiments, both a HRSG and a DCC are used to cool the gaseous exhaust stream and are each located upstream of the boost compressor. In one or more embodiments, the cooled recycle stream is directed to the main compressor and compressed to generate a compressed recycle stream. The main compressor may be a single compressor or two or more compressors operating in parallel or in series. Each compressor may comprise a single stage or multiple stages. In multiple stage compressors, interstage cooling may optionally be employed to allow for higher overall compression ratios and higher overall power output. When more than one compressor is used to compress the cooled recycle stream, the compressors taken together are considered herein to be the “main compressor.” The main compressor may be of any type suitable for the process described herein. Such compressors include, but are not limited to, axial, centrifugal, reciprocating, or twin-screw compressors and combinations thereof. In one or more embodiments, the main compressor comprises an axial compressor. Cooling and compressing the exhaust gases helps to address issues related to the large volume of gas that must be treated and the low pressure of the exhaust streams that ordinarily lead to a high cost of CO 2 capture, thus making CO 2 capture and recovery in the present systems more efficient and more cost effective. Upon exiting the main compressor, the compressed recycle stream may be directed to the combustion chamber for use as a diluent to control or otherwise regulate the temperature of the combustion and flue gas to meet the material requirements of the succeeding expander and, when desired, to maintain stoichiometric combustion conditions in the combustion chamber. In one or more embodiments, a purge stream may be diverted from the compressed recycle stream and directed to a CO 2 separation system. It will be recognized by those skilled in the art that intermediate heating, cooling, or other process operations may be required so that the purge stream enters the CO 2 separation system at conditions optimized for the particular separation process employed. In one or more embodiments, for example, a heat exchanger or other cooling unit may be used to cool the purge stream to generate a cooled purge stream that is directed to the CO 2 separation system. The heat exchanger may employ any cooling fluid suitable to effect the desired amount of cooling, including but not limited to seawater, chilled water, one or more refrigerants, other process streams, or combinations thereof. In some embodiments, the purge stream may be cooled in a cross exchanger configured to use the nitrogen-rich residual stream exiting the absorption column of the CO 2 separation system for cooling. In embodiments in which the residual stream is later expanded to generate power, cross exchanging the purge and residual streams may be especially advantageous because the additional heat provided to the residual stream may allow for increased power generation. Carbon Dioxide Separation System The combination of stoichiometric combustion (when used) in the combustion chamber and water removal through the one or more cooling units allows the CO 2 content in the exhaust gas to accumulate to about 10 vol % or higher, which is higher than exhaust gases in conventional combined-cycle systems. These effects, plus the impact of higher pressures resulting from the implementation and of a boost compressor, make the CO 2 partial pressure much higher than conventional gas turbine exhaust. Consequently, this allows for carbon capture in the CO 2 separation system using less energy-intensive solvents, such as K 2 CO 3 solvent technology. The presence of O 2 , SO X , and NO X make the use of amine solvents (e.g., MEA, DEA, MDEA, and related solvents) difficult, even with higher pressure and increased CO 2 content, since these gases can cause amine degradation. Potassium carbonate, however, is non-reactive and immune to any effects of oxygen. Although the reaction undertaken in the combustion chamber may, in some embodiments, be stoichiometric, a fraction of O 2 may nonetheless be present in the cooled purge stream due to combustion equilibrium limitations. While MEA solvents will require significant solvent reclamation and safe disposal, the use of K 2 CO 3 eliminates oxygen-based solvent degradation. Potassium carbonate easily absorbs SO X or NO X in the exhaust gas, converting these compounds to simple fertilizers, such as potassium sulfite (K 2 SO 3 ) and potassium nitrate (KNO 3 ). In particular, SO 2 , SO 3 , and NO 2 all form fairly strong acids in water, much stronger than CO 2 . Thus, they will be preferentially absorbed in the solvent solution, but will become heat stable salts (HSS) and will not be removed by regeneration. On the other hand, NO and N 2 O have low solubility and are more difficult to absorb than NO 2 , and tend to occur at lower concentrations. As simple fertilizers, the K 2 SO 3 and KNO 3 can be easily discharged in an environmentally harmless manner, so long as no other toxic compounds, such as corrosion inhibitors, activators, etc., are added to the solvent system. When the sulfate and nitrate compounds are removed, potassium hydroxide (KOH) can be added for solvent makeup. Since potassium hydroxide is a fairly inexpensive chemical, this can be accomplished rather economically. Accordingly, in one or more embodiments, the CO 2 separation system comprises an absorption column configured to absorb CO 2 from the cooled purge stream using a K 2 CO 3 solvent. As CO 2 is absorbed by the K 2 CO 3 in the absorption column, it reacts with water to form carbonic acid (H 2 CO 3 ), and then bicarbonate (HCO 3 ). The acidic part of the carbonic acid (H + ) can react with the carbonate ion (CO 3 −2 ) to form an additional bicarbonate ion. Thus, the overall reaction can be as follows: CO 2 +H 2 O+K 2 CO 3 2KHCO 3 As a result, the absorption column generates a nitrogen-rich residual stream and a bicarbonate solvent solution as described above. The nitrogen-rich residual stream from the absorption column may be used, wholly or in part, for a variety of applications. For example, the residual stream may be injected into a hydrocarbon reservoir for pressure maintenance. The residual stream may also be sold, stored, or vented. In one or more embodiments when pressure maintenance is not a viable option (or when only a portion of the residual stream is required for pressure maintenance), the residual stream may be cooled, by expansion or another method, and used to provide refrigeration in the systems described herein. For example, the cooled residual stream may be used to provide refrigeration to reduce the suction temperature of one or more compressors within the system, or to chill water for use in one or more cooling units within the system. In other embodiments when all or part of the residual stream is not used for pressure maintenance, the residual stream may instead be heated prior to expansion in a turbine so that additional power may be generated for use elsewhere in the system or for sale. Some methods of heating the residual stream include cross-exchanging the residual stream with another process stream (such as the purge stream, as described above, or another stream within the separation system or in the overall power generation system) in a heat exchanger or using a supplementary combustor to supply additional heat to the residual stream. It will be appreciated that the use of an additional combustor will require additional fuel. If a carbon-containing fuel is used in the combustor, additional CO 2 will be generated that will be unrecoverable from the residual stream. Therefore, in some embodiments, the fuel used in the combustor may be a non-carbon fuel source, such as hydrogen. The oxidant required by the supplementary combustor may be supplied via a separate oxidant stream, or there may be sufficient oxidant in the residual stream such that an additional supply of oxidant is unnecessary. Other possible methods for heating the absorption column residual stream include using a heating coil in a HRSG to heat the residual stream, using catalysis to combust any CO present in the residual stream, or heating the stream as a consequence of using the residual stream for cooling (i.e., as the residual stream provides cooling to other streams or apparatus, the stream itself is heated). In one or more embodiments, the bicarbonate solvent solution exiting the absorption column is flashed to near-atmospheric pressure via a valve or other pressure-reducing device. In some embodiments, the pressure-reducing device may be a hydraulic turbine configured to generate additional power. Once flashed to near-atmospheric pressure, the bicarbonate solvent solution may be boiled in a regeneration column to remove CO 2 and water, producing a regenerated potassium carbonate solvent that may be recycled to the absorption column. In some embodiments, the regeneration column may operate at temperatures exceeding the boiling point of water. For example, the regeneration column can operate in a temperature range from a lower limit of about 220° F., or about 230° F., or about 240° F., to an upper limit of about 280° F., about 290° F., or about 300° F. In the same or other embodiments, the regeneration column can operate at pressures ranging from about 0 psig to about 10 psig. In at least one embodiment, the regeneration column can be configured to operate at a pressure of about 3 psig. The regeneration column can be configured to use steam circulating therein to boil the bicarbonate solvent and reverse the reaction undertaken in the absorption column, thereby yielding a regenerated, lean potassium carbonate solvent suitable for recirculation to the absorption column. In at least one embodiment, an in-line pump or the like may be used to drive at least a portion of the lean potassium carbonate solvent back to the absorption column. In one or more embodiments, a portion of the lean potassium carbonate solvent recirculated to the absorption column may optionally be removed as a heat stable salt (HSS). Illustrative HSSs can include compound fertilizers, including but not limited to potassium sulfite and/or potassium nitrate. In order to make up for the loss of potassium carbonate content when an HHS is removed, and to maintain overall solution strength, a stream of potassium hydroxide can be subsequently supplied to the lean potassium carbonate stream being directed to the absorption column or to the absorption column itself. In one or more embodiments, the potassium hydroxide serves as a solvent makeup. The lean potassium carbonate solvent directed to the absorption column may optionally be directed through a first cooling unit before entering the absorption column. In one or more embodiments, the first cooling unit can be, for example, an air cooler or radiator-type heat exchanger, configured to reduce the temperature of the solvent. If used, the first cooling unit can be configured to reduce the temperature of the lean potassium carbonate solvent to temperatures ranging from about 230° F. to about 60° F. In order to generate the steam circulating in the regeneration column and maintain the required heat of regeneration, in one or more embodiments the regeneration column further comprises a reboiler fluidly coupled to the regeneration column. The reboiler can be configured to heat at least a portion of the lean potassium carbonate solvent not recirculated to the absorption column to produce a heated lean potassium carbonate solvent. The heated lean potassium carbonate solvent may then be recycled to the regeneration column to produce steam for boiling the bicarbonate solvent solution. In at least one embodiment, the reboiler can be supplied with heat from the HRSG in the EGR system. In other embodiments, however, the reboiler can be supplied with heat from another source, such as from the intermediate extraction or discharge of a steam turbine. The water included in the cooled purge stream can condense into the bicarbonate solvent solution in the absorption column and subsequently boil out in the regeneration column. Consequently, the regeneration column can further discharge the CO 2 separated from the solvent during the regeneration process and any residual water via an overhead stream. In at least one embodiment, the CO 2 (which is typically a vapor) and residual water can be directed through a second cooling unit, such as an air cooler or radiator-type heat exchanger, before being introduced to a condenser or other separation vessel. The condenser can be configured to separate the residual water from any recovered CO 2 to generate a water stream and a stream comprising primarily CO 2 . In some embodiments, at least a portion of the water exiting the condenser may be recirculated back into the regeneration column to allow the balance of water in the system to be maintained. Water is constantly introduced into the solvent via the cooled purge stream, and subsequently removed via the condenser. In order to maintain solvent conditions and strength, the water must remain in balance within the CO 2 separation system. Accordingly, the water recirculated to the regeneration column can allow water to be returned so that steam generated by the reboiler can be controlled independently of this water balance. In other words, the recirculated water can be used as feedwater for the generation of steam in the regeneration column or to raise low pressure steam from feed cooling. In the same or other embodiments, a portion of the water exiting the condenser can be disposed of as fresh process water. For example, although it may in some embodiments contain a portion of dissolved CO 2 , the water exiting the condenser can be used for irrigation water, treated to be used for boiler feed water, and/or uses as clean process water. In some embodiments, the separated CO 2 exiting the condenser can be subsequently compressed for applications such as CO 2 sequestration or storage, enhanced oil recovery, CO 2 sales, carbon capture, and/or combinations thereof. In one or more embodiments, the CO 2 stream exiting the condenser is of high purity, and comprises at least 95 mol % CO 2 , or at least 98 mol % CO 2 , or at least 99 mol % CO 2 , or at least 99.5 mol % CO 2 . Removal of Volatile Components When CO 2 is recovered via solvent absorption as described herein, the solvent may also absorb small quantities of volatile components (such as, for example, N 2 , O 2 , Ar, and CO) that will have a small solubility in a water-based solvent such as K 2 CO 3 . Upon regeneration of the solvent to release the absorbed CO 2 , these volatile components are also evolved and remain with the CO 2 . In certain situations, such as when the CO 2 is used for EOR or is injected into a reservoir for sequestration, the presence of volatiles may be undesirable. For example, the presence of oxygen may increase corrosion rates, while the presence of CO may result in safety or environmental hazards if the CO 2 were released during startup or process upset conditions. Accordingly, in certain embodiments of the present invention, the rich bicarbonate solvent solution exiting the absorption column is treated at an elevated pressure or intermediate pressure to remove volatile components before the solution is flashed to near-atmospheric pressure and regenerated in the regeneration column. The volatile components removed may include, but are not limited to, O 2 , N 2 , Ar, and CO. Two methods for removing volatiles, stripping with vapor and two-stage flashing, are described herein. It will be appreciated by those skilled in the art that variations on these methods may also be effective for removing volatiles from the bicarbonate solvent solution, and any such methods designed to remove volatiles from the solution without also removing CO 2 (or while removing only a negligible amount of CO 2 ) are considered to be within the scope of the present invention. Vapor Stripping In one or more embodiments of the present invention, volatiles are removed from the rich bicarbonate solvent solution by stripping the solvent with a vapor in a stripping column or stripping section. The vapor may be any (preferably clean) vapor that does not interact with the CO 2 in the solvent solution. Suitable vapors may include, but are not limited to, nitrogen, argon, steam, and combinations thereof. In one or more embodiments, a stripping section is incorporated as additional stages within the absorption column (generally at the bottom of the column), such that the vapor stream enters the absorption column at or near the bottom stage of the column, while the cooled purge stream is fed to the middle of the column just above the stripping stages. The rich bicarbonate solvent solution, having been stripped of volatiles, exits the bottom of the absorption column, while the stripping vapor (comprising the volatiles removed from the solvent) continues up the absorption column and exits the column as part of the nitrogen-rich residual stream. In other embodiments, the stripping section may be an additional column separate from the absorption column. In such embodiments, a vapor stream is fed to or near the bottom of the stripping column, and rich bicarbonate solvent exiting the absorption column is fed to or near the top of the stripping column. In this manner, the vapor and the bicarbonate solvent solution flow countercurrently through the stripping column. The stripping column therefore generates a first (or overhead) stream comprising the stripping vapor and the volatiles removed from the bicarbonate solvent solution and a second (or bottom) stream comprising bicarbonate solvent solution that has been stripped of volatiles. The overhead stream may be recycled to the absorption column, such that the stripping vapor (comprising the volatiles removed from the solvent) exits the absorption column as part of the nitrogen-rich residual stream. In either scenario, stripping of the bicarbonate solvent solution takes place at an elevated pressure generally at or near the pressure of the cooled purge stream entering the absorption column. By stripping the rich bicarbonate solvent at an elevated pressure, volatiles are removed from the solvent solution while essentially all of the CO 2 remains in the bicarbonate solution stream exiting the stripping section or column. The bicarbonate solvent solution may then be flashed via a valve or other pressure-reducing device (such as a hydraulic turbine) to near-atmospheric pressure and directed to the regeneration column. By removing the volatiles in this manner (i.e., prior to flashing the solvent solution to near-atmospheric pressure and regenerating the solvent), a pure or nearly pure CO 2 stream may be recovered from the CO 2 separation system. As described above, when a stripping section or column is employed, the stripping vapors will exit the absorption column in the nitrogen-rich residual stream. It will be appreciated that further processing of this stream may be required to account for the vapors present in the stream. Additionally, in embodiments in which the nitrogen-rich residual stream is expanded to generate power, it may be desirable to pass the residual stream over an oxidizing catalyst so that no CO is emitted when or if the residual stream is later vented. Excess oxygen may be added to the stream prior to entering the oxidizing catalyst to ensure full combustion of any CO. Such combustion will advantageously further heat the residual stream, thus allowing for increased power generation. Two-Stage Flash In one or more other embodiments, instead of using a stripping column or section to remove volatiles, the rich bicarbonate solvent solution exiting the absorption column may instead be flashed via a valve or other pressure-reducing device to an intermediate (or reduced) pressure between the pressure of the cooled purge stream and atmospheric pressure. By flashing to a reduced but still elevated pressure, the bicarbonate solvent solution becomes a dual-phase stream comprising a gaseous phase and a liquid phase. In one or more embodiments, the reduced pressure to which the solvent is flashed is selected so that the gaseous phase comprises the volatile components in the solution (such as nitrogen, oxygen, argon, carbon monoxide, and combinations thereof), while essentially all of the CO 2 remains in the liquid phase of the solution. In some embodiments, for example, the gaseous phase of the bicarbonate solvent solution comprises less than about 5 mol %, or less than about 3 mol %, or less than about 2 mol %, or less than about 1 mol %, or less than about 0.5 mol %, or less than about 0.1 mol % CO 2 . In certain embodiments, the dual-phase solvent solution may be directed to a flash vessel or other separation device configured to separate the gaseous volatiles from the liquid bicarbonate solvent solution comprising the CO 2 . In some embodiments, at least about 95 mol %, or at least about 97 mol %, or at least about 98 mol %, or at least about 99 mol % of the total CO 2 entering the flash vessel remains in solution and is removed with the liquid bicarbonate solvent solution from the flash vessel. The volatiles exiting the flash vessel may then be recycled to the exhaust gas recirculation system. For example, the volatiles may be recycled and combined with the cooled recycle stream upstream of the main compressor. By recycling the volatiles in this manner, CO and O 2 may be re-used for combustion, thus increasing the efficiency of the power generation system. Additionally, if any CO 2 is removed with the volatiles, it is recompressed and reprocessed through the CO 2 separation system for recovery. In one or more embodiments, the bicarbonate solvent solution exiting the flash vessel may be flashed via a second valve or other pressure-reducing device to near-atmospheric pressure and directed to the regeneration column. By removing the volatiles in this manner (i.e., at an intermediate pressure and prior to flashing the solvent solution to near-atmospheric pressure and regenerating the solvent), a pure or nearly pure CO 2 stream may be recovered from the CO 2 separation system. As may be appreciated by those skilled in the art, selection of the method and apparatus used to remove volatiles from the rich bicarbonate solvent solution may be influenced by a variety of factors. For example, the intended use of the nitrogen-rich residual stream exiting the absorption column may help determine which of the volatiles removal methods is preferred. As described previously, the use of vapor stripping to remove volatiles may be advantageous in embodiments where the nitrogen-rich residual stream is expanded to generate power, particularly when the residual stream is passed over an oxidizing catalyst to combust CO. Such combustion will further heat the residual stream, thus allowing for increased power generation. Alternatively, when the nitrogen-rich residual stream is used for pressure maintenance in hydrocarbon reservoirs, removal of volatiles via the two-stage flash described above may be preferred. By recycling the volatiles removed from the bicarbonate solvent to the EGR in the two-stage flash method rather than combining the volatiles with the residual stream (as in the vapor stripping method), fuel efficiency is maximized because all of the fuel and/or oxidant value in the volatiles is recycled and recovered. Referring now to the figures, embodiments of the invention may be best understood with reference to a base case, depicted in FIGS. 1 and 2 . FIG. 1 depicts a schematic of an illustrative integrated system 100 for power generation and CO 2 recovery. In at least one embodiment, the power generation system 100 can include a gas turbine system 102 characterized as a power-producing, closed Brayton cycle. The gas turbine system 102 can have a first or main compressor 104 coupled to an expander 106 via a shaft 108 . The shaft 108 can be any mechanical, electrical, or other power coupling, thereby allowing a portion of the mechanical energy generated by the expander 106 to drive the main compressor 104 . In at least one embodiment, the gas turbine system 102 can be a standard gas turbine, where the main compressor 104 and expander 106 form the compressor and expander ends, respectively. In other embodiments, however, the main compressor 104 and expander 106 can be individualized components in the system 102 . The gas turbine system 102 can also include a combustion chamber 110 configured to combust a fuel in line 112 mixed with a compressed oxidant in line 114 . In one or more embodiments, the fuel in line 112 can include any suitable hydrocarbon gas or liquid, such as natural gas, methane, ethane, naphtha, butane, propane, syngas, diesel, kerosene, aviation fuel, coal derived fuel, bio-fuel, oxygenated hydrocarbon feedstock, hydrogen, carbon monoxide, or combinations thereof. The compressed oxidant in line 114 can be derived from a second or inlet compressor 118 fluidly coupled to the combustion chamber 110 and adapted to compress a feed oxidant 120 . In one or more embodiments, the feed oxidant 120 can include any suitable gas containing oxygen, such as air, oxygen, oxygen-rich air, or combinations thereof. As will be described in more detail below, the combustion chamber 110 can also receive a compressed recycle stream 144 , including an exhaust gas primarily having CO 2 and nitrogen components. The compressed recycle stream 144 can be derived from the main compressor 104 and may in some embodiments be adapted to help facilitate the stoichiometric or substantially stoichiometric combustion of the compressed oxidant in line 114 and fuel in line 112 , and also to increase the CO 2 concentration in the exhaust gas. An exhaust gas in line 116 can be generated as a product of combustion of the fuel in line 112 and the compressed oxidant in line 114 , in the presence of the compressed recycle stream 144 . In at least one embodiment, the fuel in line 112 can be primarily natural gas, thereby generating an exhaust gas in line 116 including volumetric portions of vaporized water, CO 2 , nitrogen, nitrogen oxides (NO X ), and sulfur oxides (SO X ). In some embodiments, a small portion of unburned fuel or other compounds may also be present in the exhaust gas in line 116 due to combustion equilibrium limitations. The exhaust gas in line 116 can be directed to the inlet of the expander 106 . As the exhaust gas in line 116 expands through the expander 106 , it generates mechanical power to drive the main compressor 104 and also produce a gaseous exhaust in line 122 having a heightened CO 2 content resulting from the influx of the compressed recycle exhaust gas in line 144 . The power generation system 100 can also include an exhaust gas recirculation (EGR) system 124 . In one or more embodiments, the EGR system 124 can include a heat recovery steam generator (HRSG) 126 , or similar device. The gaseous exhaust in line 122 can be sent to the HRSG 126 in order to generate steam in line 130 and a cooled exhaust gas in line 132 . In some embodiments, the steam in line 130 can be sent to a steam turbine (not shown) to generate additional electrical power or to the CO 2 separator 148 to provide reboiler heat. In such embodiments, the combination of the HRSG 126 and the steam turbine can be characterized as a Rankine cycle. In combination with the gas turbine system 102 , the HRSG 126 and the steam turbine, when included, can form part of a combined-cycle power generating plant, such as a natural gas combined-cycle (NGCC) plant. The cooled exhaust gas in line 132 can be sent to at least one cooling unit 134 configured to reduce the temperature of the cooled exhaust gas in line 132 and generate a cooled recycle gas stream 140 . In one or more embodiments, the cooling unit 134 can be a direct contact cooler, trim cooler, a mechanical refrigeration unit, or combinations thereof. The cooling unit 134 can also be configured to remove a portion of condensed water via a water dropout stream (not shown) which can, in at least one embodiment, be routed to the HRSG 126 to provide a water source for the generation of additional steam in line 130 . In one or more embodiments, the cooled recycle gas stream 140 can be directed to a boost compressor 142 fluidly coupled to the cooling unit 134 . Cooling the cooled exhaust gas in line 132 in the cooling unit 134 can reduce the power required to compress the cooled recycle gas stream 140 in the boost compressor 142 . The boost compressor 142 can be configured to increase the pressure of the cooled recycle gas stream 140 before it is introduced into the main compressor 104 . As opposed to a conventional fan or blower system, the boost compressor 142 increases the overall density of the cooled recycle gas stream 140 , thereby directing an increased mass flow rate for the same volumetric flow to the main compressor 104 . Because the main compressor 104 is typically volume-flow limited, directing more mass flow through the main compressor 104 can result in a higher discharge pressure from the main compressor 104 , thereby translating into a higher pressure ratio across the expander 106 . A higher pressure ratio generated across the expander 106 can allow for higher inlet temperatures and, therefore, an increase in power and efficiency of expander 106 . This can prove advantageous since the CO 2 -rich exhaust gas in line 116 generally maintains a higher specific heat capacity. The main compressor 104 can be configured to compress the cooled recycle gas stream 140 received from the boost compressor 142 to a pressure nominally above the combustion chamber 110 pressure, thereby generating the compressed recycle stream 144 . In at least one embodiment, a purge stream 146 can be diverted from the compressed recycle stream 144 and subsequently treated in a CO 2 separator 148 to capture CO 2 via line 150 . The separated CO 2 in line 150 can be used for sales, used in another process requiring carbon dioxide, and/or compressed and injected into a terrestrial reservoir for enhanced oil recovery (EOR), sequestration, or another purpose. A residual stream 151 , essentially depleted of CO 2 and consisting primarily of nitrogen, can be derived from the CO 2 separator 148 . In one or more embodiments, the residual stream 151 can be expanded in a gas expander (not shown), such as a power-producing nitrogen expander fluidly coupled to the CO 2 separator 148 . In such embodiments, the gas expander can be optionally coupled to the inlet compressor 118 through a common shaft or other mechanical, electrical, or other power coupling, thereby allowing a portion of the power generated by the gas expander to drive the inlet compressor 118 . The residual stream 151 , whether expanded as described herein or not, can be vented to the atmosphere or implemented into other downstream applications known in the art. For example, the expanded nitrogen stream can be used in an evaporative cooling process configured to further reduce the temperature of the exhaust gas. In one or more embodiments, the exhaust gas in line 151 can be suitable for injection into a reservoir for pressure maintenance applications. In applications where methane gas is typically reinjected into hydrocarbon wells to maintain well pressures, compressing the residual stream 151 may prove advantageous. For example, pressurized nitrogen gas from line 151 can instead be injected into the hydrocarbon wells and any residual methane gas can be sold or otherwise used as a fuel in related applications, such as providing fuel in line 112 . The combustion in combustion chamber 110 may take place under stoichiometric or non-stoichiometric conditions. In some embodiments, stoichiometric or substantially stoichiometric combustion conditions may be desired. For example, the EGR system 124 as described herein, especially with the addition of the boost compressor 142 , can be implemented to achieve a higher concentration of CO 2 in the exhaust gas of the power generation system 100 , thereby allowing for more effective CO 2 separation for subsequent sequestration, pressure maintenance, or EOR applications. In certain embodiments disclosed herein, the concentration of CO 2 in the exhaust gas stream can be effectively increased to about 10 vol % or higher. To accomplish this, the combustion chamber 110 can be adapted to stoichiometrically combust the incoming mixture of fuel in line 112 and compressed oxidant in line 114 . In order to moderate the temperature of the stoichiometric combustion to meet expander 106 inlet temperature and component cooling requirements, a portion of the compressed recycle stream 144 can be simultaneously injected into the combustion chamber 110 as a diluent. Thus, embodiments of the disclosure may reduce or essentially eliminate any excess oxygen from the exhaust gas while simultaneously increasing its CO 2 composition. As such, the gaseous exhaust in line 122 can have less than about 3.0 vol % oxygen, or less than about 1.0 vol % oxygen, or less than about 0.1 vol % oxygen, or even less than about 0.001 vol % oxygen. Referring now to FIG. 2 , depicted is a CO 2 separation system 200 that can employ potassium carbonate (K 2 CO 3 ) solvent technology as described herein. The CO 2 separation system 200 can be or form at least a portion of the CO 2 separator 148 , as generally described herein with reference to FIG. 1 . In one or more embodiments, the system 200 can be configured to receive the purge stream 146 tapped from the compressed recycle stream 144 ( FIG. 1 ) at a temperature of around 800° F. and a pressures of around 270 psia to about 280 psia. The purge stream 146 , containing primarily nitrogen, CO 2 , and excess combustion water, can be cooled in a heat exchanger 202 , thereby generating a cooled purge stream in line 204 . In an embodiment, the heat exchanger 202 can generate steam, which may in some cases be integrated with the steam stream 130 from the HRSG 126 ( FIG. 1 ). Extracting CO 2 from the purge stream 146 in the CO 2 separation system 200 generates a nitrogen-rich residual stream 151 at or near the elevated pressure of the purge stream 146 . In at least one embodiment, the heat exchanger 202 can be a cross exchanger fluidly coupled to the residual stream 151 and configured to extract the heat energy associated with cooling the purge stream 146 in order to re-heat the residual stream 151 . Once reheated, the residual stream 151 can be subsequently expanded to generate mechanical power, as generally described above. The cooled purge stream in line 204 can be directed to an absorption column 206 where a solvent from line 208 is circulated, and the residual stream 151 is simultaneously discharged overhead for further downstream processing. In one or more embodiments, the solvent is a water-based salt solution of K 2 CO 3 . When compared to competing solvents, such as MEA, the K 2 CO 3 solvent is quite temperature-tolerant. As a result, the cooling of the purge stream 146 can be minimized, as needed, and a higher temperature purge stream 146 can be allowed to enter the absorption column 206 without raising thermal degradation concerns. Accordingly, the degree of cooling of the purge stream 146 can be modified to match process heat requirements, rather than cooling to avoid thermal degradation. As a result of the absorption of CO 2 by the potassium carbonate solvent in the absorption column 206 , a rich bicarbonate solvent can be discharged from the bottom of the absorption column 206 via line 210 and directed to a regeneration column 212 . In one embodiment, a first or intermediate valve 214 disposed in the line 210 can be configured to flash the bicarbonate solvent to a lower, near-atmospheric pressure before introduction to the regeneration column 212 . In at least one embodiment, the first valve 214 can be a hydraulic turbine configured to generate extra power. The regeneration column 212 can be configured to use steam circulating therein to boil the bicarbonate solvent and reverse the reaction undertaken in the absorption column 206 , thereby yielding a regenerated, lean potassium carbonate solvent suitable for recirculation via line 216 below. In at least one embodiment, an in-line pump 218 , or the like, can drive at least a portion of the lean potassium carbonate solvent via line 220 back to the absorption column 206 . The lean potassium carbonate solvent in line 220 can then be optionally directed through a first cooling unit 222 . In one or more embodiments, the first cooling unit 222 can be, for example, an air cooler or radiator-type heat exchanger, configured to reduce the temperature of the solvent. In order to generate the steam circulating in the regeneration column 212 and maintain the required heat of regeneration, at least a portion of the lean potassium carbonate solvent in line 216 can be directed to a reboiler 219 via line 217 . The reboiler 219 can be configured to increase the temperature of the lean potassium carbonate solvent in line 217 , and return a heated regenerated potassium carbonate solvent back to the regeneration column via line 221 . In at least one embodiment, the reboiler 219 can be supplied with heat from the HRSG 126 ( FIG. 1 ). In other embodiments, however, the reboiler 219 can be supplied with heat from the discharge of a backpressure type steam turbine, or from an extraction sidestream from a condensing type steam turbine. The water included in the purge stream 146 can condense into the solvent solution in the absorption column 206 , and subsequently boil out in the regeneration column 212 . Consequently, the regeneration column 212 can further discharge CO 2 vapor and any residual water via overhead line 224 . In at least one embodiment, the CO 2 vapor and residual water can be directed through a second cooling unit 226 , such as an air cooler or radiator-type heat exchanger, before being introduced into a condenser 228 . The condenser 228 can be configured to separate the residual water from any recovered CO 2 and direct the separated water into line 230 below while feeding the recovered CO 2 into line 150 overhead. As can be appreciated, line 150 can be the same line 150 as described above with reference to FIG. 1 . In at least one embodiment, the separated CO 2 in line 150 can be subsequently compressed for applications such as CO 2 sequestration, enhanced oil recovery, CO 2 sales, carbon capture, and/or combinations thereof. In one embodiment, at least a portion of the separated water in line 230 can be recirculated back into the regeneration column 212 via line 234 using a pump 232 to allow the balance of water in the system to be maintained. Water is constantly introduced into the solvent via stream 204 , and subsequently removed via lines 236 , 150 , and 151 . In order to maintain solvent conditions and strength, the water must remain in balance within the system 200 . Accordingly, the water recirculated in line 234 can allow water to be returned so that steam raised in line 221 can be controlled independently of this water balance. In other embodiments, a portion of the residual water in line 230 can be disposed of as fresh process water via line 236 . For example, the water in line 236 can be used for irrigation water, treated to be used for boiler feed water, and/or other process water. Referring now to FIG. 3 , depicted is an illustrative embodiment of a CO 2 separation system 300 according to the invention, similar in some respects to the system 200 of FIG. 2 but incorporating a stripping section to remove volatiles from the rich bicarbonate solution before regeneration of the solvent. As such, the entire system 300 will not be described in detail but may be best understood with reference to FIG. 2 . As depicted in system 300 of FIG. 3 , the rich bicarbonate solvent discharged from the bottom of the absorption column 206 via stream 210 can be directed to a stripping section 310 , where volatile components may be stripped from the rich bicarbonate solvent using a vapor stream 312 . The vapor stream 312 comprises a preferably clean vapor, which may be any vapor configured to remove volatile components that will not interact with CO 2 . In some embodiments, the vapor stream 312 may comprise nitrogen, argon, steam, or combinations thereof. In one or more embodiments (not shown), the stripping section 310 may be incorporated as additional stages at the bottom of the absorption column 206 . In other embodiments, the stripping section 310 may be a separate column from the absorption column as shown in FIG. 3 . In one or more embodiments, the stripping section 310 operates at an elevated pressure similar to that of the cooled purge stream 204 . The stripping section 310 generates a first or overhead stream 314 comprising the stripping vapor and the volatile components stripped from the rich bicarbonate solution and a second stream 316 comprising the stripped bicarbonate solvent solution. The overhead stream 314 is recirculated to the absorption column 206 , while the bicarbonate solvent solution in line 316 is directed the regeneration column 212 . Line 316 may include a valve 318 disposed therein configured to flash the bicarbonate solvent to a lower, near-atmospheric pressure before introduction to the regeneration column 212 . In at least one embodiment, the first valve 318 can be a hydraulic turbine configured to generate extra power. Complete solvent regeneration can then take place as described above with reference to system 200 . Referring now to FIG. 4 , depicted is an illustrative embodiment of a CO 2 separation system 400 according to the invention, similar in some respects to the system 200 of FIG. 2 but incorporating a preliminary flash to an intermediate pressure to remove volatiles from the rich bicarbonate solution before regeneration of the solvent. As such, the entire system 400 will not be described in detail but may be best understood with reference to FIG. 2 . As depicted in system 400 of FIG. 4 , the rich bicarbonate solvent can be discharged from the bottom of the absorption column 206 via line 210 and reduced in pressure via a first valve 408 before being introduced into a flash vessel 410 . In one or more embodiments, the first valve 408 can be configured to reduce the pressure of the bicarbonate solvent from a pressure at or near that of the cooled purge stream 204 to an intermediate pressure sufficient to release volatile components such as N 2 , O 2 , Ar, and CO from the bicarbonate solvent while keeping CO 2 in the liquid phase of the solution. The resulting reduced-pressure dual phase solvent solution exiting the first valve 408 may then be directed to the flash vessel 410 , where the phases are separated. The gaseous phase of the reduced-pressure solvent solution, comprising the volatile components described previously, is removed from the flash vessel 410 via volatile stream 412 , while the liquid phase of the reduced-pressure solvent solution is removed from the flash vessel via line 414 and directed to the regeneration column 212 . In one or more embodiments, volatile stream 412 may be recycled to the exhaust gas recirculation system 124 ( FIG. 1 ). For example, as illustrated in system 500 of FIG. 5 , the volatile stream 412 may be recycled and added to the cooled recycle gas 140 before the cooled recycle gas 140 is directed to the main compressor 104 . Referring again to the system 400 of FIG. 4 , the reduced-pressure solvent solution in line 414 may be flashed to a lower, near-atmospheric pressure using a second valve 416 before being directed into the regeneration column 212 . Complete solvent regeneration can then take place as described above with reference to system 200 . At least one benefit derived from the separation systems 300 and 400 of FIGS. 3 and 4 , respectively, is the ability to produce a pure or nearly pure CO 2 stream from the regeneration column 212 . The contaminants present in the CO 2 stream in line 210 can include water and volatile gases (described above) dissolved into the circulating solvent. Because the systems of FIGS. 3 and 4 are adapted to remove essentially all of the volatile gases while keeping the CO 2 in the solution, the regeneration column 212 overhead stream 224 is left with essentially only high purity CO 2 and water. In one or more embodiments, a portion of the CO 2 in line 150 can optionally be directed into a purge line (not shown) and captured for non-EOR uses, such as chemical feedstock, food production, etc. Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. All numerical values are considered to be “about” or “approximately” the stated value. Furthermore, all patents and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted. While the present disclosure may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the disclosure is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present disclosure includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Description

Topics

Download Full PDF Version (Non-Commercial Use)

Patent Citations (746)

    Publication numberPublication dateAssigneeTitle
    WO-2010141777-A1December 09, 2010Exxonmobil Upstream Research Company, Office Of Technology Licensing Georgia Tech Research CorporationCombustor systems and methods for using same
    US-5992388-ANovember 30, 1999Patentanwalt Hans Rudolf GachnangFuel gas admixing process and device
    US-4762543-AAugust 09, 1988Amoco CorporationCarbon dioxide recovery
    US-7313916-B2January 01, 2008Philip Morris Usa Inc.Method and apparatus for generating power by combustion of vaporized fuel
    US-6615589-B2September 09, 2003Air Products And Chemicals, Inc.Process and apparatus for the generation of power
    US-5850732-ADecember 22, 1998Capstone Turbine CorporationLow emissions combustion system for a gas turbine engine
    US-2011205837-A1August 25, 2011Iav Gmbh Ingenieurgesellschaft Auto Und VerkehrStatic mixer for an exhaust gas system of an internal combustion engine
    US-6743829-B2June 01, 2004Bp Corporation North America Inc.Integrated processing of natural gas into liquid products
    US-4561245-ADecember 31, 1985Atlantic Richfield CompanyTurbine anti-icing system
    US-5640840-AJune 24, 1997Westinghouse Electric CorporationRecuperative steam cooled gas turbine method and apparatus
    US-2013269360-A1October 17, 2013General Electric CompanyMethod and system for controlling a powerplant during low-load operations
    US-7562519-B1July 21, 2009Florida Turbine Technologies, Inc.Gas turbine engine with an air cooled bearing
    US-7874350-B2January 25, 2011Precision Combustion, Inc.Reducing the energy requirements for the production of heavy oil
    US-5444971-AAugust 29, 1995Holenberger; Charles R.Method and apparatus for cooling the inlet air of gas turbine and internal combustion engine prime movers
    US-2012247105-A1October 04, 2012Exxonmobile Upstream Research CompanyLow Emission Power Generation and Hydrocarbon Recovery Systems and Methods
    US-2009120087-A1May 14, 2009Siegfried Sumser, Wolfram SchmidExhaust gas turbocharger in an internal combustion engine
    US-6170264-B2December 31, 1969
    US-2007107430-A1May 17, 2007Wolfram Schmid, Siegfried SumserInternal combustion engine having two exhaust gas turbocharger
    US-6324867-B1December 04, 2001Exxonmobil Oil CorporationProcess and system for liquefying natural gas
    US-8191361-B2June 05, 2012Lightsail Energy, Inc.Compressed air energy storage system utilizing two-phase flow to facilitate heat exchange
    US-7343742-B2March 18, 2008Bayerische Motoren Werke AktiengesellschaftExhaust turbocharger
    US-4380895-AApril 26, 1983Rolls-Royce LimitedCombustion chamber for a gas turbine engine having a variable rate diffuser upstream of air inlet means
    US-5839283-ANovember 24, 1998Abb Research Ltd.Mixing ducts for a gas-turbine annular combustion chamber
    US-6993916-B2February 07, 2006General Electric CompanyBurner tube and method for mixing air and gas in a gas turbine engine
    US-4236378-ADecember 02, 1980General Electric CompanySectoral combustor for burning low-BTU fuel gas
    US-6450256-B2September 17, 2002The University Of Wyoming Research CorporationEnhanced coalbed gas production system
    US-4488865-ADecember 18, 1984Arkansas Patents, Inc.Pulsing combustion
    US-7434384-B2October 14, 2008United Technologies CorporationFluid mixer with an integral fluid capture ducts forming auxiliary secondary chutes at the discharge end of said ducts
    US-7882692-B2February 08, 2011Clean Energy Systems, Inc.Zero emissions closed rankine cycle power system
    US-7097925-B2August 29, 2006Questair Technologies Inc.High temperature fuel cell power plant
    US-7096942-B1August 29, 2006Shell Oil CompanyIn situ thermal processing of a relatively permeable formation while controlling pressure
    US-6745573-B2June 08, 2004American Air Liquide, Inc.Integrated air separation and power generation process
    US-8215105-B2July 10, 2012Lightsail Energy Inc.Compressed air energy storage system utilizing two-phase flow to facilitate heat exchange
    US-6289677-B1September 18, 2001Pratt & Whitney Canada Corp.Gas turbine fuel injector
    US-7594386-B2September 29, 2009Compressor Controls CorporationApparatus for the prevention of critical process variable excursions in one or more turbomachines
    US-6367258-B1April 09, 2002Bechtel CorporationMethod and apparatus for vaporizing liquid natural gas in a combined cycle power plant
    US-7681394-B2March 23, 2010The United States Of America, As Represented By The Administrator Of The U.S. Environmental Protection AgencyControl methods for low emission internal combustion system
    US-7011154-B2March 14, 2006Shell Oil CompanyIn situ recovery from a kerogen and liquid hydrocarbon containing formation
    US-6722436-B2April 20, 2004Precision Drilling Technology Services Group Inc.Apparatus and method for operating an internal combustion engine to reduce free oxygen contained within engine exhaust gas
    US-7482500-B2January 27, 2009Basf AktiengesellschaftPreparation of butadiene
    US-5271905-ADecember 21, 1993Mobil Oil CorporationApparatus for multi-stage fast fluidized bed regeneration of catalyst
    WO-2009120779-A3January 07, 2010Exxonmobil Upstream Research CompanyProduction d'électricité à faible émission et systèmes et procédés de récupération d'hydrocarbures
    US-6484507-B1November 26, 2002Louis A. PradtMethod and apparatus for controlling liquid droplet size and quantity in a stream of gas
    US-2884758-AMay 05, 1959Bbc Brown Boveri & CieRegulating device for burner operating with simultaneous combustion of gaseous and liquid fuel
    US-4222240-ASeptember 16, 1980Castellano Thomas PTurbocharged engine
    US-6702570-B2March 09, 2004Praxair Technology Inc.Firing method for a heat consuming device utilizing oxy-fuel combustion
    US-2005236602-A1October 27, 2005Fermin Viteri, Anderson Roger EWorking fluid compositions for use in semi-closed Brayton cycle gas turbine power systems
    US-6449954-B2September 17, 2002Alstom (Switzerland) LtdProcess and apparatus for the recovery of water from the flue gas of a combined cycle power station
    US-5265410-ANovember 30, 1993Mitsubishi Jukogyo Kabushiki KaishaPower generation system
    US-7901488-B2March 08, 2011Board Of Regents, The University Of Texas SystemRegeneration of an aqueous solution from an acid gas absorption process by matrix stripping
    US-3949548-AApril 13, 1976Lockwood Jr Hanford NGas turbine regeneration system
    US-5238395-AAugust 24, 1993John Zink CompanyLow nox gas burner apparatus and methods
    US-4066214-AJanuary 03, 1978The Boeing Company, Aeritalia S.P.A.Gas turbine exhaust nozzle for controlled temperature flow across adjoining airfoils
    WO-2012003078-A1January 05, 2012Exxonmobil Upstream Research CompanyCombustion stœchiométrique avec recirculation du gaz d'échappement et refroidisseur à contact direct
    US-8074439-B2December 13, 2011Foret Plasma Labs, LlcSystem, method and apparatus for lean combustion with plasma from an electrical arc
    US-6508209-B1January 21, 2003R. Kirk Collier, Jr.Reformed natural gas for powering an internal combustion engine
    US-6606861-B2August 19, 2003United Technologies CorporationLow emissions combustor for a gas turbine engine
    US-6487863-B1December 03, 2002Siemens Westinghouse Power CorporationMethod and apparatus for cooling high temperature components in a gas turbine
    US-5361586-ANovember 08, 1994Westinghouse Electric CorporationGas turbine ultra low NOx combustor
    US-4898001-AFebruary 06, 1990Hitachi, Ltd.Gas turbine combustor
    US-7162875-B2January 16, 2007Rolls-Royce PlcMethod and system for controlling fuel supply in a combustion turbine engine
    US-6805483-B2October 19, 2004General Electric CompanySystem for determining gas turbine firing and combustion reference temperature having correction for water content in combustion air
    US-5771868-AJune 30, 1998Turbodyne Systems, Inc.Turbocharging systems for internal combustion engines
    US-6612291-B2September 02, 2003Nissan Motor Co., Ltd.Fuel injection controlling system for a diesel engine
    GB-2117053-BJune 05, 1985Boc Group PlcGas turbines and engines
    US-5073105-ADecember 17, 1991Callidus Technologies Inc.Low NOx burner assemblies
    US-4002721-AJanuary 11, 1977Chevron Research CompanyProcess improvement in the absorption of acid gas from a feed gas
    WO-2012003080-A1January 05, 2012Exxonmobil Upstream Research CompanySystèmes et procédés de production d'électricité à faible taux d'émission
    US-6360528-B1March 26, 2002General Electric CompanyChevron exhaust nozzle for a gas turbine engine
    US-7650744-B2January 26, 2010General Electric CompanySystems and methods of reducing NOx emissions in gas turbine systems and internal combustion engines
    US-5628182-AMay 13, 1997Mowill; R. JanStar combustor with dilution ports in can portions
    US-6969123-B2November 29, 2005Shell Oil CompanyUpgrading and mining of coal
    US-6824710-B2November 30, 2004Clean Energy Systems, Inc.Working fluid compositions for use in semi-closed brayton cycle gas turbine power systems
    US-6216549-B1April 17, 2001The United States Of America As Represented By The Secretary Of The InteriorCollapsible bag sediment/water quality flow-weighted sampler
    US-2010162703-A1July 01, 2010Shell Internationale Research Maatschappij B.V.Process for reducing carbon dioxide emission in a power plant
    US-2007245736-A1October 25, 2007Eastman Chemical CompanyProcess for superheated steam
    US-2007006592-A1January 11, 2007Chellappa Balan, Bowman Michael J, Hibshman Joell R Ii, Evulet Andrei T, Molaison Jennifer LSystems and methods for power generation with carbon dioxide isolation
    US-8372251-B2February 12, 2013General Electric CompanySystem for protecting gasifier surfaces from corrosion
    US-2008178611-A1July 31, 2008Foster Wheeler Usa CorporationEcological Liquefied Natural Gas (LNG) Vaporizer System
    US-2007044479-A1March 01, 2007Harry Brandt, Brandt Muriel R, Anderson Roger E, Pronske Keith L, Fermin Viteri, Scott MacadamHydrogen production from an oxyfuel combustor
    US-2014000273-A1January 02, 2014Franklin F. Mittricker, Richard A. Huntington, Loren K. Starcher, Sulabh K. Dhanuka, Omar Angus SitesLow Emission Turbine Systems Incorporating Inlet Compressor Oxidant Control Apparatus And Methods Related Thereto
    US-4445842-AMay 01, 1984Thermal Systems Engineering, Inc.Recuperative burner with exhaust gas recirculation means
    US-4606721-AAugust 19, 1986Tifa LimitedCombustion chamber noise suppressor
    US-2004170559-A1September 02, 2004Frank Hershkowitz, Segarich Robert L.Hydrogen manufacture using pressure swing reforming
    US-6332313-B1December 25, 2001Rolls-Royce PlcCombustion chamber with separate, valved air mixing passages for separate combustion zones
    US-7906304-B2March 15, 2011Geosynfuels, LlcMethod and bioreactor for producing synfuel from carbonaceous material
    US-5832712-ANovember 10, 1998Kvaerner AsaMethod for removing carbon dioxide from exhaust gases
    US-7124589-B2October 24, 2006David NearyPower cogeneration system and apparatus means for improved high thermal efficiencies and ultra-low emissions
    US-2010326084-A1December 30, 2010Anderson Roger E, Fermin Viteri, Hoffman Lawrence C, Cheryl Lynn Hoffman, Pronske Keith LMethods of oxy-combustion power generation using low heating value fuel
    US-4543784-AOctober 01, 1985Rolls-Royce LimitedExhaust flow mixers and nozzles
    US-8388919-B2March 05, 2013Co2Crc Technologies Pty LtdPlant and process for removing carbon dioxide from gas streams
    US-4204401-AMay 27, 1980The Hydragon CorporationTurbine engine with exhaust gas recirculation
    US-5581998-ADecember 10, 1996Craig; Joe D.Biomass fuel turbine combuster
    US-6598402-B2July 29, 2003Hitachi, Ltd.Exhaust gas recirculation type combined plant
    US-5147111-ASeptember 15, 1992Atlantic Richfield CompanyCavity induced stimulation method of coal degasification wells
    US-6725665-B2April 27, 2004Alstom Technology LtdMethod of operation of gas turbine having multiple burners
    US-4160640-AJuly 10, 1979Maev Vladimir A, Kuznetsov Andrei L, Lamm Jury A, Ivakhnenko Viktor V, Sudarev Anatoly V, Prokushenkov Nikolai NMethod of fuel burning in combustion chambers and annular combustion chamber for carrying same into effect
    US-6248794-B1June 19, 2001Atlantic Richfield CompanyIntegrated process for converting hydrocarbon gas to liquids
    US-7513099-B2April 07, 2009Siemens AktiengesellschaftTemperature measuring device and regulation of the temperature of hot gas of a gas turbine
    US-7673685-B2March 09, 2010Statoil Asa, Petrose (The Petroleum Oil & Gas Corporation of SA (Pty) Ltd)Method for oil recovery from an oil field
    US-5394688-AMarch 07, 1995Westinghouse Electric CorporationGas turbine combustor swirl vane arrangement
    US-2012023963-A1February 02, 2012General Electric CompanyPower plant and method of operation
    US-7918906-B2April 05, 2011Pioneer Energy Inc.Compact natural gas steam reformer with linear countercurrent heat exchanger
    US-7846401-B2December 07, 2010Exxonmobil Research And Engineering CompanyControlled combustion for regenerative reactors
    US-6945029-B2September 20, 2005Clean Energy Systems, Inc.Low pollution power generation system with ion transfer membrane air separation
    US-5584182-ADecember 17, 1996Abb Management AgCombustion chamber with premixing burner and jet propellent exhaust gas recirculation
    WO-2011028322-A1March 10, 2011Exxonmobil Upstream Research CompanyLow emission power generation and hydrocarbon recovery systems and methods
    US-6499990-B1December 31, 2002Zeeco, Inc.Low NOx burner apparatus and method
    US-7305831-B2December 11, 2007Alstom Technology Ltd.Gas turbine having exhaust recirculation
    US-6694735-B2February 24, 2004Daimlerchrysler AgInternal combustion engine with an exhaust turbocharger and an exhaust-gas recirculation device
    US-8209192-B2June 26, 2012Osum Oil Sands Corp.Method of managing carbon reduction for hydrocarbon producers
    US-6412302-B1July 02, 2002Abb Lummus Global, Inc. - Randall DivisionLNG production using dual independent expander refrigeration cycles
    US-3926591-ADecember 16, 1975Linde AgRegeneration of scrubbing agent used for the removal of co' 2 'and h' 2's from gases containing polymerizable hydrocarbons
    US-6748004-B2June 08, 2004Air Liquide America, L.P.Methods and apparatus for improved energy efficient control of an electric arc furnace fume extraction system
    US-2014007590-A1January 09, 2014Richard A. Huntington, Franklin F. Mittricker, Omer Angus Sites, Sulabh K. Dhanuka, Dennis M. O'Dea, Russell H. Oelfke, Robert D. DentonSystems and Methods For Carbon Dioxide Capture In Low Emission Turbine Systems
    US-3561895-AFebruary 09, 1971Exxon Research Engineering CoControl of fuel gas combustion properties in inspirating burners
    US-5974780-ANovember 02, 1999Santos; Rolando R.Method for reducing the production of NOX in a gas turbine
    US-2009199566-A1August 13, 2009Etienne Lebas, Alexandre RojeyCo2 emission-free energy production by gas turbine
    US-2011000221-A1January 06, 2011Moses Minta, Mittricker Franklin F, Peter Rasmussen, Starcher Loren K, Rasmussen Chad C, Wilkins James T, Meidel Jr Richard WLow Emission Power Generation and Hydrocarbon Recovery Systems and Methods
    US-6032465-AMarch 07, 2000Alliedsignal Inc.Integral turbine exhaust gas recirculation control valve
    US-7513100-B2April 07, 2009General Electric CompanySystems for low emission gas turbine energy generation
    US-7353655-B2April 08, 2008Alstom Technology LtdMethod and apparatus for achieving power augmentation in gas turbine using wet compression
    US-4653278-AMarch 31, 1987General Electric CompanyGas turbine engine carburetor
    US-7841186-B2November 30, 2010Power Systems Mfg., LlcInlet bleed heat and power augmentation for a gas turbine engine
    US-6945052-B2September 20, 2005Alstom Technology Ltd.Methods and apparatus for starting up emission-free gas-turbine power stations
    US-5950417-ASeptember 14, 1999Foster Wheeler Energy International Inc.Topping combustor for low oxygen vitiated air streams
    US-6389814-B2May 21, 2002Clean Energy Systems, Inc.Hydrocarbon combustion power generation system with CO2 sequestration
    US-8225600-B2July 24, 2012Theis Joseph RMethod for remediating emissions
    US-4479484-AOctober 30, 1984Arkansas Patents, Inc.Pulsing combustion
    US-5154596-AOctober 13, 1992John Zink Company, A Division Of Koch Engineering Company, Inc.Methods and apparatus for burning fuel with low NOx formation
    US-6598399-B2July 29, 2003Alstom (Switzerland) LtdIntegrated power plant and method of operating such an integrated power plant
    US-5634329-AJune 03, 1997Abb Carbon AbMethod of maintaining a nominal working temperature of flue gases in a PFBC power plant
    US-3705492-ADecember 12, 1972Gen Motors CorpRegenerative gas turbine system
    US-7753039-B2July 13, 2010Toyota Jidosha Kabushiki KaishaExhaust gas control apparatus of an internal combustion engine
    US-7493769-B2February 24, 2009General Electric CompanyAssembly and method for cooling rear bearing and exhaust frame of gas turbine
    US-6752620-B2June 22, 2004Air Products And Chemicals, Inc.Large scale vortex devices for improved burner operation
    US-4946597-AAugust 07, 1990Esso Resources Canada LimitedLow temperature bitumen recovery process
    US-4498289-AFebruary 12, 1985Ian OsgerbyCarbon dioxide power cycle
    US-7305817-B2December 11, 2007General Electric CompanySinuous chevron exhaust nozzle
    US-6817187-B2November 16, 2004Alstom (Switzerland) Ltd.Re-fired gas turbine engine
    US-7491250-B2February 17, 2009Exxonmobil Research And Engineering CompanyPressure swing reforming
    US-4117671-AOctober 03, 1978The Boeing CompanyNoise suppressing exhaust mixer assembly for ducted-fan, turbojet engine
    US-5713206-AFebruary 03, 1998Westinghouse Electric CorporationGas turbine ultra low NOx combustor
    US-6672863-B2January 06, 2004Alstom Technology LtdBurner with exhaust gas recirculation
    US-8166766-B2May 01, 2012General Electric CompanySystem and method to generate electricity
    US-7503178-B2March 17, 2009Alstom Technology LtdThermal power plant with sequential combustion and reduced-CO2 emission, and a method for operating a plant of this type
    US-7815873-B2October 19, 2010Exxonmobil Research And Engineering CompanyControlled combustion for regenerative reactors with mixer/flow distributor
    US-5044932-ASeptember 03, 1991It-Mcgill Pollution Control Systems, Inc., Tulsa Heaters, Inc.Nitrogen oxide control using internally recirculated flue gas
    US-8051638-B2November 08, 2011General Electric CompanySystems and methods for exhaust gas recirculation (EGR) for turbine engines
    US-7793494-B2September 14, 2010J. Eberspaecher Gmbh & Co., KgStatic mixer and exhaust gas treatment device
    US-7197880-B2April 03, 2007United States Department Of EnergyLean blowoff detection sensor
    US-5680764-AOctober 28, 1997Clean Energy Systems, Inc.Clean air engines transportation and other power applications
    US-2013269361-A1October 17, 2013General Electric CompanyMethods relating to reheat combustion turbine engines with exhaust gas recirculation
    US-2013269362-A1October 17, 2013General Electric CompanyMethods, systems and apparatus relating to combustion turbine power plants with exhaust gas recirculation
    US-2014000271-A1January 02, 2014Franklin F. Mittricker, Richard A. Huntington, Sulabh K. Dhanuka, Omar Angus SitesSystems and Methods For Controlling Stoichiometric Combustion In Low Emission Turbine Systems
    US-4112676-ASeptember 12, 1978Westinghouse Electric Corp.Hybrid combustor with staged injection of pre-mixed fuel
    US-7752850-B2July 13, 2010Siemens Energy, Inc.Controlled pilot oxidizer for a gas turbine combustor
    US-5197289-AMarch 30, 1993General Electric CompanyDouble dome combustor
    US-3643430-AFebruary 22, 1972United Aircraft CorpSmoke reduction combustion chamber
    US-6887069-B1May 03, 2005The United States Of America As Represented By The United States Department Of EnergyReal-time combustion controls and diagnostics sensors (CCADS)
    US-7148261-B2December 12, 2006Exxonmobil Chemical Patents Inc.Methanol manufacture using pressure swing reforming
    US-2010278710-A1November 04, 2010Mitsubishi Heavy Industries, Ltd.Method and system for recovering high-purity co2 from gasification gas
    US-5332036-AJuly 26, 1994The Boc Group, Inc.Method of recovery of natural gases from underground coal formations
    US-8038416-B2October 18, 2011Yamada Manufacturing Co., Ltd.Oil pump pressure control device
    US-7922871-B2April 12, 2011Recycled Carbon Fibre LimitedRecycling carbon fibre
    US-7152409-B2December 26, 2006Kawasaki Jukogyo Kabushiki KaishaDynamic control system and method for multi-combustor catalytic gas turbine engine
    US-4817387-AApril 04, 1989Hamilton C. Forman, TrusteeTurbocharger/supercharger control device
    US-7225623-B2June 05, 2007General Electric CompanyTrapped vortex cavity afterburner
    US-7763227-B2July 27, 2010Shell Oil CompanyProcess for the manufacture of carbon disulphide
    US-5590518-AJanuary 07, 1997California Energy CommissionHydrogen-rich fuel, closed-loop cooled, and reheat enhanced gas turbine powerplants
    US-6269882-B1August 07, 2001Shell Oil CompanyMethod for ignition of flameless combustor
    US-2013269310-A1October 17, 2013General Electric CompanySystems and apparatus relating to reheat combustion turbine engines with exhaust gas recirculation
    WO-2005064232-A1July 14, 2005Alstom Technology LtdThermal power plant with sequential combustion and reduced co2 emissions and method for operating a plant of this type
    US-5402847-AApril 04, 1995Conoco Inc.Coal bed methane recovery
    US-6256976-B1July 10, 2001Hitachi, Ltd.Exhaust gas recirculation type combined plant
    US-5572862-ANovember 12, 1996Mowill Rolf JanConvectively cooled, single stage, fully premixed fuel/air combustor for gas turbine engine modules
    US-5930990-AAugust 03, 1999The Dow Chemical CompanyMethod and apparatus for achieving power augmentation in gas turbines via wet compression
    US-5255506-AOctober 26, 1993General Motors CorporationSolid fuel combustion system for gas turbine engine
    US-2013232980-A1September 12, 2013General Electric CompanySystem for supplying a working fluid to a combustor
    US-2009241506-A1October 01, 2009Siemens AktiengesellschaftGas turbine system and method
    US-2007272201-A1November 29, 2007Ebara CorporationCombustion Apparatus and Combustion Method
    US-7827794-B1November 09, 2010Clean Energy Systems, Inc.Ultra low emissions fast starting power plant
    WO-2010066048-A1June 17, 2010Her Majesty The Queen In Right Of Canada As Represented By The Minister Of Natural ResourcesHigh pressure direct contact oxy-fired steam generator
    US-4077206-AMarch 07, 1978The Boeing CompanyGas turbine mixer apparatus for suppressing engine core noise and engine fan noise
    US-2012031581-A1February 09, 2012General Electric CompanyThermal control system for fault detection and mitigation within a power generation system
    US-7299868-B2November 27, 2007Alexei ZapadinskiMethod and system for recovery of hydrocarbons from a hydrocarbon-bearing information
    US-2010115960-A1May 13, 2010Alstom Technology LtdGas Turbine Installation with Flue Gas Recirculation
    US-2013125555-A1May 23, 2013Franklin F. Mittricker, Richard A. HuntingtonSystems and Methods For Optimizing Stoichiometric Combustion
    US-4344486-AAugust 17, 1982Standard Oil Company (Indiana)Method for enhanced oil recovery
    US-5901547-AMay 11, 1999Air Products And Chemicals, Inc.Operation method for integrated gasification combined cycle power generation system
    US-5657631-AAugust 19, 1997B.B.A. Research & Development, Inc.Injector for turbine engines
    US-6470682-B2October 29, 2002The United States Of America As Represented By The Administrator Of The United States Environmental Protection AgencyLow emission, diesel-cycle engine
    US-7749311-B2July 06, 2010Taiheiyo Cement CorporationSystem and method for treating dust contained in extracted cement kiln combustion gas
    US-7717173-B2May 18, 2010Ecycling, LLCMethods of improving oil or gas production with recycled, increased sodium water
    US-8316784-B2November 27, 2012Air Products And Chemicals, Inc.Oxy/fuel combustion system with minimized flue gas recirculation
    US-6640548-B2November 04, 2003Siemens Westinghouse Power CorporationApparatus and method for combusting low quality fuel
    US-6477859-B2November 12, 2002Praxair Technology, Inc.Integrated heat exchanger system for producing carbon dioxide
    US-6745624-B2June 08, 2004Ford Global Technologies, LlcMethod and system for calibrating a tire pressure sensing system for an automotive vehicle
    US-8038773-B2October 18, 2011Jupiter Oxygen CorporationIntegrated capture of fossil fuel gas pollutants including CO2 with energy recovery
    US-4681678-AJuly 21, 1987Combustion Engineering, Inc.Sample dilution system for supercritical fluid chromatography
    US-2011036082-A1February 17, 2011Faurecia Systemes D'echappementExhaust element comprising a static means for mixing an additive into the exhaust gases
    US-2010267123-A1October 21, 2010Louis WibberleyMethod for co2 transfer from gas streams to ammonia solutions
    US-4569310-AFebruary 11, 1986Arkansas Patents, Inc.Pulsing combustion
    US-5344307-ASeptember 06, 1994Koch Engineering Company, Inc.Methods and apparatus for burning fuel with low Nox formation
    US-7921633-B2April 12, 2011Siemens Energy, Inc.System and method employing direct gasification for power generation
    US-6202400-B1March 20, 2001Hitachi, Ltd.Gas turbine exhaust recirculation method and apparatus
    US-6584775-B1July 01, 2003AlstomControl of primary measures for reducing the formation of thermal nitrogen oxides in gas turbines
    US-4050239-ASeptember 27, 1977Motoren- Und Turbinen-Union Munchen Gmbh, M.A.N. Maybach Mercedes-BenzThermodynamic prime mover with heat exchanger
    US-5725054-AMarch 10, 1998Board Of Supervisors Of Louisiana State University And Agricultural & Mechanical CollegeEnhancement of residual oil recovery using a mixture of nitrogen or methane diluted with carbon dioxide in a single-well injection process
    US-7943097-B2May 17, 2011Catalytic Solutions, Inc.Reactor system for reducing NOx emissions from boilers
    US-7357857-B2April 15, 2008Baker Hughes IncorporatedProcess for extracting bitumen
    US-2002053207-A1May 09, 2002Helmut Finger, Peter Fledersbacher, Siegfried Sumser, Friedrich WirbeleitInternal combustion engine with exhaust gas turbocharger and compound power turbine
    US-7104319-B2September 12, 2006Shell Oil CompanyIn situ thermal processing of a heavy oil diatomite formation
    US-8080225-B2December 20, 2011Specialist Process Technologies LimitedFunctional fluid and a process for the preparation of the functional fluid
    US-7168265-B2January 30, 2007Bp Corporation North America Inc.Integrated processing of natural gas into liquid products
    US-7618606-B2November 17, 2009The Ohio State UniversitySeparation of carbon dioxide (CO2) from gas mixtures
    US-6532745-B1March 18, 2003David L. NearyPartially-open gas turbine cycle providing high thermal efficiencies and ultra-low emissions
    US-7183328-B2February 27, 2007Exxonmobil Chemical Patents Inc.Methanol manufacture using pressure swing reforming
    WO-2012018459-A3April 12, 2012Dresser-Rand CompanyProcédé et système pour la réduction de la consommation de gaz d'étanchéité et la stabilisation de la réduction de pression dans des systèmes de compression à haute pression
    US-6742506-B1June 01, 2004Saab Automobile AbCombustion engine having exhaust gas recirculation
    US-7980312-B1July 19, 2011Hill Gilman A, Affholter Joseph AIntegrated in situ retorting and refining of oil shale
    US-8261823-B1September 11, 2012Hill Gilman A, Affholter Joseph AIntegrated in situ retorting and refining of oil shale
    US-6276171-B1August 21, 2001L'air Liquide, Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges ClaudeIntegrated apparatus for generating power and/or oxygen enriched fluid, process for the operation thereof
    WO-2012128928-A1September 27, 2012Exxonmobile Upstream Research CompanySystèmes et procédés de capture du dioxyde de carbone dans des systèmes de turbines combinées à faible émission
    US-6314721-B1November 13, 2001United Technologies CorporationTabbed nozzle for jet noise suppression
    US-8245493-B2August 21, 2012General Electric CompanyPower plant and control method
    US-2011162353-A1July 07, 2011Renault TrucksMixing device in an exhaust gas pipe
    US-6813889-B2November 09, 2004Hitachi, Ltd.Gas turbine combustor and operating method thereof
    US-2013283808-A1October 31, 2013General Electric CompanySystem and method for cooling a gas turbine with an exhaust gas provided by the gas turbine
    US-2010180565-A1July 22, 2010General Electric CompanyMethods for increasing carbon dioxide content in gas turbine exhaust and systems for achieving the same
    US-7655071-B2February 02, 2010Shell Oil CompanyProcess for cooling down a hot flue gas stream
    US-2008223038-A1September 18, 2008Behr Gmbh & Co. KgArrangement for Recirculating and Cooling Exhaust Gas of an Internal Combustion Engine
    US-6170264-B1January 09, 2001Clean Energy Systems, Inc.Hydrocarbon combustion power generation system with CO2 sequestration
    US-2012260660-A1October 18, 2012General Electric CompanyStoichiometric Exhaust Gas Recirculation Combustor
    US-4414334-ANovember 08, 1983Phillips Petroleum CompanyOxygen scavenging with enzymes
    US-8036813-B2October 11, 2011C.R.F. Societa Consortile Per AzioniEGR control system
    US-2009255242-A1October 15, 2009Woodward Governor CompanyLow Pressure Drop Mixer for Radial Mixing of Internal Combustion Engine Exhaust Flows, Combustor Incorporating Same, and Methods of Mixing
    US-8240142-B2August 14, 2012Lightsail Energy Inc.Compressed air energy storage system utilizing two-phase flow to facilitate heat exchange
    US-8377401-B2February 19, 2013Air Liquid Process & Construction, Inc., L'air Liquide Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges ClaudeProcess and apparatus for the separation of a gaseous mixture
    US-2006158961-A1July 20, 2006Hans Ruscheweyh, Stefan Leser, Michael KaatzMixing device and mixing method
    US-8453461-B2June 04, 2013General Electric CompanyPower plant and method of operation
    US-6946419-B2September 20, 2005Alstom Technology LtdProcess for the regeneration of a catalyst plant and apparatus for performing the process
    US-7931712-B2April 26, 2011Pioneer Energy Inc.Natural gas steam reforming method with linear countercurrent heat exchanger
    US-2008038598-A1February 14, 2008Berlowitz Paul J, Rajeev Agnihotri, Frank Hershkowitz, Rados Novica S, Frederick Jeffrey W, Calabro David C, Partridge Randall DFuel cell fuel processor with hydrogen buffering and staged membrane
    US-2011072779-A1March 31, 2011General Electric CompanySystem and method using low emissions gas turbine cycle with partial air separation
    US-7065972-B2June 27, 2006Honeywell International, Inc.Fuel-air mixing apparatus for reducing gas turbine combustor exhaust emissions
    US-8065874-B2November 29, 2011Lightsale Energy, Inc.Compressed air energy storage system utilizing two-phase flow to facilitate heat exchange
    US-6305929-B1October 23, 2001Suk Ho Chung, School Of Mechanical And Aerospace Engineering, Seoul National UniversityLaser-induced ignition system using a cavity
    US-2013104563-A1May 02, 2013Russell H. Oelfke, Moses MintaLow Emission Triple-Cycle Power Generation Systems and Methods
    US-6838071-B1January 04, 2005Den Norske Stats Oljeselskap A.S.Process for preparing a H2-rich gas and a CO2-rich gas at high pressure
    CA-2645450-A1September 13, 2007Western Oil Sands Usa, Inc., Willem P. C. Duyvesteyn, Julian Kift, Raymond L. Morley, Marathon Oil Sands (Usa) Inc., Marathon Oil Canada Corporation, Marathon Canadian Oil Sands Holding LimitedProcessing asphaltene-containing tailings
    US-5968349-AOctober 19, 1999Bhp Minerals International Inc.Extraction of bitumen from bitumen froth and biotreatment of bitumen froth tailings generated from tar sands
    US-6183241-B2December 31, 1969
    US-6698412-B2March 02, 2004Catalytica Energy Systems, Inc.Catalyst placement in combustion cylinder for reduction on NOx and particulate soot
    US-6216459-B1April 17, 2001Daimlerchrysler AgExhaust gas re-circulation arrangement
    US-7966822-B2June 28, 2011General Electric CompanyReverse-flow gas turbine combustion system
    US-8065870-B2November 29, 2011Volvo Technology CorporationDevice and method for reduction of a gas component in an exhaust gas flow of a combustion engine
    US-2013091853-A1April 18, 2013Robert D. Denton, Himanshu Gupta, Richard Huntington, Moses Minta, Franklin F. Mittricker, Loren K. StarcherStoichiometric Combustion With Exhaust Gas Recirculation and Direct Contact Cooler
    US-2005144961-A1July 07, 2005General Electric CompanySystem and method for cogeneration of hydrogen and electricity
    US-7481275-B2January 27, 2009Statoil AsaPlant and a method for increased oil recovery
    US-6668541-B2December 30, 2003Allison Advanced Development CompanyMethod and apparatus for spraying fuel within a gas turbine engine
    US-4498288-AFebruary 12, 1985General Electric CompanyFuel injection staged sectoral combustor for burning low-BTU fuel gas
    US-7488857-B2February 10, 2009Basf AktiengesellschaftMethod for the production of butadiene and 1-butene
    US-4435153-AMarch 06, 1984Hitachi, Ltd.Low Btu gas burner
    US-7895822-B2March 01, 2011General Electric CompanySystems and methods for power generation with carbon dioxide isolation
    US-5183232-AFebruary 02, 1993Gale John AInterlocking strain relief shelf bracket
    US-5765363-AJune 16, 1998Mowill; R. JanConvectively cooled, single stage, fully premixed controllable fuel/air combustor with tangential admission
    US-6094916-AAugust 01, 2000Allison Engine CompanyDry low oxides of nitrogen lean premix module for industrial gas turbine engines
    US-6363709-B2April 02, 2002Hitachi, Ltd.Exhaust gas recirculation type combined plant
    US-8101146-B2January 24, 2012Johnson Matthey Public Limited CompanyCatalysts for the reduction of ammonia emission from rich-burn exhaust
    US-5819540-AOctober 13, 1998Massarani; MadhatRich-quench-lean combustor for use with a fuel having a high vanadium content and jet engine or gas turbine system having such combustors
    US-6283087-B1September 04, 2001Kjell IsaksenEnhanced method of closed vessel combustion
    EP-0654639-B1September 16, 1998Westinghouse Electric CorporationAilettes de tourbillon ajustables pour bruleur de turbine à gaz
    US-6851413-B1February 08, 2005Ronnell Company, Inc.Method and apparatus to increase combustion efficiency and to reduce exhaust gas pollutants from combustion of a fuel
    US-5135387-AAugust 04, 1992It-Mcgill Environmental Systems, Inc., Tulsa Heaters, Inc.Nitrogen oxide control using internally recirculated flue gas
    US-6907737-B2June 21, 2005Exxon Mobil Upstream Research CompanyMethod for utilizing gas reserves with low methane concentrations and high inert gas concentrations for fueling gas turbines
    US-7631493-B2December 15, 2009Nissan Motor Co., Ltd.Exhaust gas purification control of diesel engine
    US-7976803-B2July 12, 2011Co2Crc Technologies Pty Ltd.Plant and process for removing carbon dioxide from gas streams
    US-4253301-AMarch 03, 1981General Electric CompanyFuel injection staged sectoral combustor for burning low-BTU fuel gas
    US-5836164-ANovember 17, 1998Hitachi, Ltd.Gas turbine combustor
    US-7942003-B2May 17, 2011SnecmaDual-injector fuel injector system
    US-4085578-AApril 25, 1978General Electric CompanyProduction of water gas as a load leveling approach for coal gasification power plants
    US-6383461-B1May 07, 2002John Zink Company, LlcFuel dilution methods and apparatus for NOx reduction
    US-2012144837-A1June 14, 2012Chad Rasmussen, Huntington Richard A, O'dea Dennis, Mittricker Franklin F, Frank HershkowitzLow Emission Power Generation and Hydrocarbon Recovery Systems and Methods
    US-6988549-B1January 24, 2006John A BabcockSAGD-plus
    US-7610759-B2November 03, 2009Hitachi, Ltd.Combustor and combustion method for combustor
    US-8348551-B2January 08, 2013Terratherm, Inc.Method and system for treating contaminated materials
    US-6731501-B1May 04, 2004Jian-Roung ChengHeat dissipating device for dissipating heat generated by a disk drive module inside a computer housing
    US-6201029-B1March 13, 2001Marathon Oil CompanyStaged combustion of a low heating value fuel gas for driving a gas turbine
    US-8266913-B2September 18, 2012General Electric CompanyPower plant and method of use
    US-7654330-B2February 02, 2010Pioneer Energy, Inc.Apparatus, methods, and systems for extracting petroleum using a portable coal reformer
    WO-2006107209-A1October 12, 2006Sargas AsLow co2 thermal powerplant
    US-6767527-B1July 27, 2004Norsk Hydro AsaMethod for recovering CO2
    US-7789159-B1September 07, 2010Bader Mansour SMethods to de-sulfate saline streams
    US-5685158-ANovember 11, 1997General Electric CompanyCompressor rotor cooling system for a gas turbine
    US-7053128-B2May 30, 2006Exxonmobil Research And Engineering CompanyHydrocarbon synthesis process using pressure swing reforming
    US-5295350-AMarch 22, 1994Texaco Inc.Combined power cycle with liquefied natural gas (LNG) and synthesis or fuel gas
    WO-2013163045-A1October 31, 2013General Electric Company, Exxonmobil Upstream Research CompanySystème et procédé de recirculation de gaz d'échappement destinés à être utilisés dans une pluralité de trajets d'écoulement dans un moteur à turbine à gaz
    US-4858428-AAugust 22, 1989Paul Marius AAdvanced integrated propulsion system with total optimized cycle for gas turbines
    CA-2231749-A1September 19, 1998Mitsubishi Heavy Industries, Ltd., Shigemi Mandai, Tetsuo Gora, Hiroyuki Nishida, Mitsuru InadaLow-nox combustor and gas turbine apparatus employing said combustor
    US-8127558-B2March 06, 2012Siemens Energy, Inc.Gas turbine engine adapted for use in combination with an apparatus for separating a portion of oxygen from compressed air
    US-8424601-B2April 23, 2013Ex-Tar Technologies Inc.System and method for minimizing the negative enviromental impact of the oilsands industry
    US-2008010967-A1January 17, 2008Timothy Griffin, Dominikus Buecker, Abbott David JMethod for Generating Energy in an Energy Generating Installation Having a Gas Turbine, and Energy Generating Installation Useful for Carrying Out the Method
    US-6247316-B1June 19, 2001Clean Energy Systems, Inc.Clean air engines for transportation and other power applications
    US-6904815-B2June 14, 2005General Electric CompanyConfigurable multi-point sampling method and system for representative gas composition measurements in a stratified gas flow stream
    US-7914764-B2March 29, 2011Exxonmobil Research And Engineering CompanyHydrogen manufacture using pressure swing reforming
    US-6945087-B2September 20, 2005Ford Global Technologies, LlcMethod and system for calibrating a tire pressure sensing system for an automotive vehicle
    WO-9906674-A1February 11, 1999Nonox Engineering AbEnvironment friendly high efficiency power generation method based on gaseous fuels and a combined cycle with a nitrogen free gas turbine and a conventional steam turbine
    US-4092095-AMay 30, 1978Combustion Unlimited IncorporatedCombustor for waste gases
    US-7824179-B2November 02, 2010Nfk Holdings Co.Device and method for feeding fuel
    US-8061120-B2November 22, 2011Herng Shinn HwangCatalytic EGR oxidizer for IC engines and gas turbines
    US-7010921-B2March 14, 2006General Electric CompanyMethod and apparatus for cooling combustor liner and transition piece of a gas turbine
    US-6062026-AMay 16, 2000Turbodyne Systems, Inc.Turbocharging systems for internal combustion engines
    US-7137256-B1November 21, 2006Peter Stuttaford, Nuria Margarit-Bel, Yan Chen, Khalid Oumejjoud, Stephen JenningsMethod of operating a combustion system for increased turndown capability
    US-7674443-B1March 09, 2010Irvin DavisZero emission gasification, power generation, carbon oxides management and metallurgical reduction processes, apparatus, systems, and integration thereof
    US-6298652-B1October 09, 2001Exxon Mobil Chemical Patents Inc.Method for utilizing gas reserves with low methane concentrations and high inert gas concentrations for fueling gas turbines
    US-4480985-ANovember 06, 1984Arkansas Patents, Inc.Pulsing combustion
    US-6263659-B1July 24, 2001Air Products And Chemicals, Inc.Air separation process integrated with gas turbine combustion engine driver
    US-2004068981-A1April 15, 2004Siefker Robert G., Vittal Baily Ramachandra, Baker Von David, Khalid Syed Arif, Loebig James CarlExhaust mixer and apparatus using same
    US-6484503-B1November 26, 2002Arie RazCompression and condensation of turbine exhaust steam
    US-6412278-B1July 02, 2002Borgwarner, Inc.Hydraulically powered exhaust gas recirculation system
    US-2012023962-A1February 02, 2012General Electric CompanyPower plant and method of operation
    US-7789658-B2September 07, 2010Uop LlcFired heater
    US-6345493-B1February 12, 2002Air Products And Chemicals, Inc.Air separation process and system with gas turbine drivers
    US-5142866-ASeptember 01, 1992Toyota Jidosha Kabushiki KaishaSequential turbocharger system for an internal combustion engine
    US-2008202123-A1August 28, 2008Siemens Power Generation, Inc.System and method for oxygen separation in an integrated gasification combined cycle system
    WO-2007068682-A1June 21, 2007Shell Internationale Research Maatschappij B.V.Procede ameliore de recuperation de petrole et procede de sequestration de dioxyde de carbone
    US-6684643-B2February 03, 2004Alstom Technology LtdProcess for the operation of a gas turbine plant
    US-7931888-B2April 26, 2011Praxair Technology, Inc.Hydrogen production method
    US-4602614-AJuly 29, 1986United Stirling, Inc.Hybrid solar/combustion powered receiver
    US-5724805-AMarch 10, 1998University Of Massachusetts-LowellPower plant with carbon dioxide capture and zero pollutant emissions
    US-5275552-AJanuary 04, 1994John Zink Company, A Division Of Koch Engineering Co. Inc.Low NOx gas burner apparatus and methods
    US-8454350-B2June 04, 2013General Electric CompanyDiluent shroud for combustor
    US-7302801-B2December 04, 2007Hamilton Sundstrand CorporationLean-staged pyrospin combustor
    US-6502383-B1January 07, 2003General Electric CompanyStub airfoil exhaust nozzle
    US-7614352-B2November 10, 2009Her Majesty The Queen In Right Of Canada, As Represented By The Minister Of Natural ResourcesIn-situ capture of carbon dioxide and sulphur dioxide in a fluidized bed combustor
    US-2009235637-A1September 24, 2009Foret Plasma Labs, LlcSystem, method and apparatus for lean combustion with plasma from an electrical arc
    US-6523349-B2February 25, 2003Clean Energy Systems, Inc.Clean air engines for transportation and other power applications
    US-8226912-B2July 24, 2012Air Products And Chemicals, Inc.Method of treating a gaseous mixture comprising hydrogen, carbon dioxide and hydrogen sulphide
    US-2012023956-A1February 02, 2012General Electric CompanyPower plant and method of operation
    US-6886334-B2May 03, 2005Nissan Motor Co., Ltd.Combustion control of diesel engine
    US-6539716-B2April 01, 2003Daimlerchrysler AgInternal combustion engine with exhaust gas turbocharger and compound power turbine
    EP-0453059-B1June 22, 1994Mitsubishi Jukogyo Kabushiki KaishaPower generation system
    US-6298654-B1October 09, 2001VERMES GéZA, BEéR JáNOS M.Ambient pressure gas turbine system
    WO-2008142009-A1November 27, 2008L'air Liquide Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges ClaudeProcess for purifying a gas by cpsa having two regeneration stages, and purification unit for implementing this process
    US-4352269-AOctober 05, 1982Mechanical Technology IncorporatedStirling engine combustor
    US-7909898-B2March 22, 2011Air Products And Chemicals, Inc.Method of treating a gaseous mixture comprising hydrogen and carbon dioxide
    US-2012032810-A1February 09, 2012General Electric CompanyThermal measurement system for fault detection within a power generation system
    US-4224991-ASeptember 30, 1980Messerschmitt-Bolkow-Blohm GmbhMethod and apparatus for extracting crude oil from previously tapped deposits
    US-7690204-B2April 06, 2010Praxair Technology, Inc.Method of maintaining a fuel Wobbe index in an IGCC installation
    US-4345426-AAugust 24, 1982Egnell Rolf A, Sjoestedt Carl GoeranDevice for burning fuel with air
    US-6082093-AJuly 04, 2000Solar Turbines Inc.Combustion air control system for a gas turbine engine
    US-6675579-B1January 13, 2004Ford Global Technologies, LlcHCCI engine intake/exhaust systems for fast inlet temperature and pressure control with intake pressure boosting
    US-2012023957-A1February 02, 2012General Electric CompanyPower plant and method of operation
    US-8475160-B2July 02, 2013Vast Power Portfolio, LlcLow emissions combustion apparatus and method
    US-8262343-B2September 11, 2012Vast Power Portfolio, LlcWet compression apparatus and method
    US-6823852-B2November 30, 2004Collier Technologies, LlcLow-emission internal combustion engine
    US-2012023960-A1February 02, 2012General Electric CompanyPower plant and control method
    US-2012085100-A1April 12, 2012General Electric CompanyCombustor with a Lean Pre-Nozzle Fuel Injection System
    US-8220268-B2July 17, 2012Caterpillar Inc.Turbine engine having fuel-cooled air intercooling
    US-7763163-B2July 27, 2010Saudi Arabian Oil CompanyProcess for removal of nitrogen and poly-nuclear aromatics from hydrocracker feedstocks
    US-2013125554-A1May 23, 2013Franklin F. Mittricker, Richard A. Huntington, Dennis M. O'DeaSystems and Methods For Exhaust Gas Extraction
    US-2011048010-A1March 03, 2011Alstom Technology LtdApparatus and method for close coupling of heat recovery steam generators with gas turbines
    US-6016658-AJanuary 25, 2000Capstone Turbine CorporationLow emissions combustion system for a gas turbine engine
    WO-2012170114-A1December 13, 2012Exxonmobil Upstream Research CompanyMethods and systems for providing steam
    US-2013091854-A1April 18, 2013Himanshu Gupta, Richard Huntington, Moses K. Minta, Franklin F. Mittricker, Loren K. StarcherStoichiometric Combustion of Enriched Air With Exhaust Gas Recirculation
    US-5388395-AFebruary 14, 1995Air Products And Chemicals, Inc.Use of nitrogen from an air separation unit as gas turbine air compressor feed refrigerant to improve power output
    US-2008118310-A1May 22, 2008Graham Robert GAll-ceramic heat exchangers, systems in which they are used and processes for the use of such systems
    WO-2008155242-A1December 24, 2008Alstom Technology LtdInstallation de turbine à gaz avec recirculation des gaz d'échappement
    US-6374594-B1April 23, 2002Power Systems Mfg., LlcSilo/can-annular low emissions combustor
    US-8097230-B2January 17, 2012Shell Oil CompanyProcess for the manufacture of carbon disulphide and use of a liquid stream comprising carbon disulphide for enhanced oil recovery
    US-7536252-B1May 19, 2009General Electric CompanyMethod and system for controlling a flowrate of a recirculated exhaust gas
    US-7056482-B2June 06, 2006Cansolv Technologies Inc.Method for recovery of CO2 from gas streams
    US-6237339-B1May 29, 2001Norsk Hydro AsaProcess for generating power and/or heat comprising a mixed conducting membrane reactor
    US-2010126176-A1May 27, 2010Ik Soo KimDual swirler
    US-2006183009-A1August 17, 2006Berlowitz Paul J, Rajeev Agnihotri, Frank Hershkowitz, Rados Novica S, Frederick Jeffrey WFuel cell fuel processor with hydrogen buffering
    US-7691788-B2April 06, 2010Schlumberger Technology CorporationCompositions and methods of using same in producing heavy oil and bitumen
    US-2008034727-A1February 14, 2008Fluor Technologies CorporationTriple Cycle Power Plant
    US-2014013766-A1January 16, 2014Franklin F. Mittricker, Sulabh K. Dhanuka, Richard A. Huntington, Omar Angus Sites, Dennis M. O'Dea, Russell H. OelfkeSystems and Methods For Carbon Dioxide Captrue and Power Generation In Low Emission Turbine Systems
    US-4528811-AJuly 16, 1985General Electric Co.Closed-cycle gas turbine chemical processor
    US-6637183-B2October 28, 2003Clean Energy Systems, Inc.Semi-closed brayton cycle gas turbine power systems
    US-6971242-B2December 06, 2005Caterpillar Inc.Burner for a gas turbine engine
    US-8201402-B2June 19, 2012Lightsail Energy, Inc.Compressed air energy storage system utilizing two-phase flow to facilitate heat exchange
    US-5325660-AJuly 05, 1994Hitachi, Ltd.Method of burning a premixed gas in a combustor cap
    US-3841382-AOctober 15, 1974Maloney Crawford TankGlycol regenerator using controller gas stripping under vacuum
    US-4684465-AAugust 04, 1987Combustion Engineering, Inc.Supercritical fluid chromatograph with pneumatically controlled pump
    US-2009038247-A1February 12, 2009Tapco International CorporationExterior trim pieces with weather stripping and colored protective layer
    WO-2010044958-A1April 22, 2010Exxonmobil Upstream Research CompanyMethods and systems for controlling the products of combustion
    US-7726114-B2June 01, 2010General Electric CompanyIntegrated combustor-heat exchanger and systems for power generation using the same
    US-8453462-B2June 04, 2013General Electric CompanyMethod of operating a stoichiometric exhaust gas recirculation power plant
    US-8205455-B2June 26, 2012General Electric CompanyPower plant and method of operation
    US-2014020398-A1January 23, 2014Franklin F. Mittricker, Richard A. Huntington, Loren K. Starcher, Omar Angus SitesMethods of Varying Low Emission Turbine Gas Recycle Circuits and Systems and Apparatus Related Thereto
    US-5542840-AAugust 06, 1996Zeeco Inc.Burner for combusting gas and/or liquid fuel with low NOx production
    US-6230103-B1May 08, 2001Power Tech Associates, Inc.Method of determining concentration of exhaust components in a gas turbine engine
    US-7789944-B2September 07, 2010Taiheiyo Cement CorporationSystem and method for treating dust contained in extracted cement kiln combustion gas
    US-2010170253-A1July 08, 2010General Electric CompanyMethod and apparatus for fuel injection in a turbine engine
    US-4753666-AJune 28, 1988Chevron Research CompanyDistillative processing of CO2 and hydrocarbons for enhanced oil recovery
    US-4171349-AOctober 16, 1979Institutul De Cercetari Si Proiectari Pentru Petrol Si GazeDesulfurization process and installation for hydrocarbon reservoir fluids produced by wells
    US-2010310439-A1December 09, 2010Theodorus Johannes Brok, Gerardus Petrus Van Der ZwetProcess for removal of hydrogen sulphide and carbon dioxide from an acid gas stream
    US-6202574-B1March 20, 2001Abb Alstom Power Inc.Combustion method and apparatus for producing a carbon dioxide end product
    US-7237385-B2July 03, 2007Alstom Technology Ltd.Method of using a combustion chamber for a gas turbine
    US-7637093-B2December 29, 2009Fluor Technologies CorporationHumid air turbine cycle with carbon dioxide recovery
    US-2012023966-A1February 02, 2012General Electric CompanyPower plant start-up method
    US-8047007-B2November 01, 2011Pioneer Energy Inc.Methods for generating electricity from carbonaceous material with substantially no carbon dioxide emissions
    US-5123248-AJune 23, 1992General Electric CompanyLow emissions combustor
    US-6035641-AMarch 14, 2000Membane Technology And Research, Inc.Membrane-augmented power generation
    US-7146969-B2December 12, 2006Daimlerchrysler AgMotor vehicle comprising an activated carbon filter and method for regenerating an activated carbon filter
    US-7574856-B2August 18, 2009Fluor Technologies CorporationConfigurations and methods for power generation with integrated LNG regasification
    US-2011138766-A1June 16, 2011General Electric CompanySystem and method of improving emission performance of a gas turbine
    US-2004166034-A1August 26, 2004Alstom Technology LtdProcess for the regeneration of a catalyst plant and apparatus for performing the process
    US-2007234702-A1October 11, 2007Hagen David L, Gary Ginter, Alberto Traverso, Bill Goheen, Mcguire Allan, Janet Rankin, Aristide Massardo, Klaus Ronald LThermodynamic cycles with thermal diluent
    US-6079974-AJune 27, 2000Beloit Technologies, Inc.Combustion chamber to accommodate a split-stream of recycled gases
    US-6370870-B1April 16, 2002Nissan Motor Co., Ltd.Exhaust gas purifying device
    WO-2008074980-A1June 26, 2008Hydrogen Energy International LimitedProcédé
    US-6209325-B1April 03, 2001European Gas Turbines LimitedCombustor for gas- or liquid-fueled turbine
    US-6301889-B1October 16, 2001Caterpillar Inc.Turbocharger with exhaust gas recirculation
    US-2011088379-A1April 21, 2011General Electric CompanyExhaust gas diffuser
    WO-2013155214-A1October 17, 2013General Electric Company, Exxonmobil Upstream Research CompanySystème et procédé pour un système de turbine à gaz à recirculation des gaz d'échappement stœchiométrique
    US-2013269356-A1October 17, 2013General Electric CompanyMethod and system for controlling a stoichiometric egr system on a regenerative reheat system
    US-8240153-B2August 14, 2012General Electric CompanyMethod and system for controlling a set point for extracting air from a compressor to provide turbine cooling air in a gas turbine
    US-7815892-B2October 19, 2010Exxonmobil Research And Engineering CompanyIntegration of hydrogen and power generation using pressure swing reforming
    WO-2011003606-A1January 13, 2011Bergen Teknologioverføring AsProcédé de récupération de pétrole améliorée à partir de réservoirs géologiques
    US-5715673-AFebruary 10, 1998Clean Energy Systems, Inc.Reduced pollution power generation system
    US-6301888-B1October 16, 2001The United States Of America As Represented By The Administrator Of The Environmental Protection AgencyLow emission, diesel-cycle engine
    US-2011265447-A1November 03, 2011Cunningham Mark HuzzardGas turbine engine exhaust mixer
    US-7635408-B2December 22, 2009Fluor Technologies CorporationMethods and configurations for acid gas enrichment
    US-7644573-B2January 12, 2010General Electric CompanyGas turbine inlet conditioning system and method
    US-7896105-B2March 01, 2011Exxonmobil Upstream Research CompanyMethod of drilling and production hydrocarbons from subsurface formations
    US-6821501-B2November 23, 2004Shell Oil CompanyIntegrated flameless distributed combustion/steam reforming membrane reactor for hydrogen production and use thereof in zero emissions hybrid power system
    US-4613299-ASeptember 23, 1986Tommy BackheimDevice for combustion of a fuel and oxygen mixed with a part of the combustion gases formed during the combustion
    WO-2012003077-A1January 05, 2012Exxonmobil Upstream Research CompanyLow emission triple-cycle power generation systems and methods
    US-5937634-AAugust 17, 1999Solar Turbines IncEmission control for a gas turbine engine
    US-4976100-ADecember 11, 1990Westinghouse Electric Corp.System and method for heat recovery in a combined cycle power plant
    US-2010111784-A1May 06, 2010Fluor Technologies CorporationConfigurations And Methods For Carbon Dioxide And Hydrogen Production From Gasification Streams
    US-6901760-B2June 07, 2005Alstom Technology LtdProcess for operation of a burner with controlled axial central air mass flow
    US-6467270-B2October 22, 2002Cummins Inc.Exhaust gas recirculation air handling system for an internal combustion engine
    US-6910335-B2June 28, 2005Clean Energy Systems, Inc.Semi-closed Brayton cycle gas turbine power systems
    US-6405536-B1June 18, 2002Wu-Chi Ho, Ling-Chia Weng, Henry JanGas turbine combustor burning LBTU fuel gas
    US-5468270-ANovember 21, 1995Borszynski; Wac AwAssembly for wet cleaning of combustion gases derived from combustion processes, especially the combustion of coal, coke and fuel oil
    US-8196413-B2June 12, 2012Fluor Technologies CorporationConfigurations and methods for thermal integration of LNG regasification and power plants
    US-8176982-B2May 15, 2012Osum Oil Sands Corp.Method of controlling a recovery and upgrading operation in a reservoir
    US-2009229263-A1September 17, 2009General Electric CompanyMethod for controlling a flowrate of a recirculated exhaust gas
    US-2003134241-A1July 17, 2003Ovidiu Marin, Erwin Penfornis, Yves Bourhis, Benjamin BugeatProcess and apparatus of combustion for reduction of nitrogen oxide emissions
    US-6256994-B1July 10, 2001Air Products And Chemicals, Inc.Operation of an air separation process with a combustion engine for the production of atmospheric gas products and electric power
    US-8627643-B2January 14, 2014General Electric CompanySystem and method for measuring temperature within a turbine system
    US-6994491-B2February 07, 2006Kittle Paul AGas recovery from landfills using aqueous foam
    US-7045553-B2May 16, 2006Exxonmobil Research And Engineering CompanyHydrocarbon synthesis process using pressure swing reforming
    US-7654320-B2February 02, 2010Occidental Energy Ventures Corp.System and method for processing a mixture of hydrocarbon and CO2 gas produced from a hydrocarbon reservoir
    WO-2012003489-A3August 01, 2013Exxonmobil Upstream Research Company, Georgia Tech Research CorporationSystèmes et procédés de gestion de la combustion d'un carburant
    US-7015271-B2March 21, 2006Ppg Industries Ohio, Inc.Hydrophobic particulate inorganic oxides and polymeric compositions containing same
    US-6981358-B2January 03, 2006Alstom Technology Ltd.Reheat combustion system for a gas turbine
    US-7985399-B2July 26, 2011Praxair Technology, Inc.Hydrogen production method and facility
    US-4399652-AAugust 23, 1983Curtiss-Wright CorporationLow BTU gas combustor
    US-8616294-B2December 31, 2013Pioneer Energy, Inc.Systems and methods for generating in-situ carbon dioxide driver gas for use in enhanced oil recovery
    US-5141049-AAugust 25, 1992The Badger Company, Inc.Treatment of heat exchangers to reduce corrosion and by-product reactions
    US-5014785-AMay 14, 1991Amoco CorporationMethane production from carbonaceous subterranean formations
    US-8281596-B1October 09, 2012General Electric CompanyCombustor assembly for a turbomachine
    US-8206669-B2June 26, 2012Air Products And Chemicals, Inc.Method and apparatus for treating a sour gas
    US-6820428-B2November 23, 2004Wylie Inventions Company, Inc.Supercritical combined cycle for generating electric power
    US-8062617-B2November 22, 2011Haldor Topsøe A/SProcess and catalyst system for SCR of NOx
    US-5924275-AJuly 20, 1999General Electric Co.Center burner in a multi-burner combustor
    EP-0770771-A1May 02, 1997Asea Brown Boveri AgZwischengekühlter Verdichter
    US-5490378-AFebruary 13, 1996Mtu Motoren- Und Turbinen-Union Muenchen GmbhGas turbine combustor
    US-7721543-B2May 25, 2010Southwest Research InstituteSystem and method for cooling a combustion gas charge
    US-2009117024-A1May 07, 2009Geoffrey Gerald Weedon, Bjarne TorgersenProcess for the Production of Hydrogen with Co-Production and Capture of Carbon Dioxide
    US-8377184-B2February 19, 2013Mitsubishi Heavy Industries, Ltd.CO2 recovery apparatus and CO2 recovery method
    US-2013104562-A1May 02, 2013Russell H. Oelfke, Moses MintaLow Emission Tripe-Cycle Power Generation Systems and Methods
    US-7926292-B2April 19, 2011Gas Technology InstitutePartial oxidation gas turbine cooling
    US-6418725-B1July 16, 2002Kabushiki Kaisha ToshibaGas turbine staged control method
    US-8409307-B2April 02, 2013Praxair Technology, Inc.Gasification and steam methane reforming integrated polygeneration method and system
    US-7498009-B2March 03, 2009Dana Uv, Inc.Controlled spectrum ultraviolet radiation pollution control process
    US-6266954-B1July 31, 2001General Electric Co.Double wall bearing cone
    US-3631672-AJanuary 04, 1972Gen ElectricEductor cooled gas turbine casing
    US-6202442-B1March 20, 2001L'air Liquide, Societe Anonyme Pour L'etude Et L'expoitation Des Procedes Georges ClaudeIntegrated apparatus for generating power and/or oxygen enriched fluid and process for the operation thereof
    US-6282901-B1September 04, 2001L'air Liquide, Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges ClaudeIntegrated air separation process
    US-7942008-B2May 17, 2011General Electric CompanyMethod and system for reducing power plant emissions
    US-7762084-B2July 27, 2010Rolls-Royce Canada, Ltd.System and method for controlling the working line position in a gas turbine engine compressor
    US-2007249738-A1October 25, 2007Haynes Joel M, Herbon John T, Dean Anthony J, Ali Mohamed APremixed partial oxidation syngas generator
    US-2009064653-A1March 12, 2009Hagen David L, Ian Wylie, Mcguire L AllanPartial load combustion cycles
    US-7381393-B2June 03, 2008The Regents Of The University Of CaliforniaProcess for sulfur removal suitable for treating high-pressure gas streams
    US-7540150-B2June 02, 2009Daimler AgInternal combustion engine having two exhaust gas turbocharger
    US-8347600-B2January 08, 2013General Electric CompanyPower plant and method of operation
    US-7739864-B2June 22, 2010General Electric CompanySystems and methods for power generation with carbon dioxide isolation
    US-7523603-B2April 28, 2009Vast Power Portfolio, LlcTrifluid reactor
    US-7363764-B2April 29, 2008Alstom Technology LtdGas turbine power plant and method of operating the same
    US-8268044-B2September 18, 2012Air Products And Chemicals, Inc.Separation of a sour syngas stream
    US-8397482-B2March 19, 2013General Electric CompanyDry 3-way catalytic reduction of gas turbine NOx
    US-7318317-B2January 15, 2008Alstom Technology Ltd.Combustion chamber for a gas turbine
    US-8555796-B2October 15, 2013Air Products And Chemicals, Inc.Process temperature control in oxy/fuel combustion system
    US-2009157230-A1June 18, 2009General Electric CompanyMethod for controlling a flowrate of a recirculated exhaust gas
    US-6622470-B2September 23, 2003Clean Energy Systems, Inc.Semi-closed brayton cycle gas turbine power systems
    US-7185497-B2March 06, 2007Honeywell International, Inc.Rich quick mix combustion system
    US-7802434-B2September 28, 2010General Electric CompanySystems and processes for reducing NOx emissions
    US-4637792-AJanuary 20, 1987Arkansas Patents, Inc.Pulsing combustion
    US-4577462-AMarch 25, 1986Rolls-Royce LimitedExhaust mixing in turbofan aeroengines
    US-6622645-B2September 23, 2003Honeywell International Inc.Combustion optimization with inferential sensor
    US-2011300493-A1December 08, 2011Franklin F Mittricker, Starcher Loren K, Chad Rasmussen, Huntington Richard A, Frank HershkowitzMethods and Systems For Controlling The Products of Combustion
    US-2007144747-A1June 28, 2007Hce, LlcCoal bed pretreatment for enhanced carbon dioxide sequestration
    US-5740786-AApril 21, 1998Mercedes-Benz AgInternal combustion engine with an exhaust gas recirculation system
    US-6183241-B1February 06, 2001Midwest Research InstituteUniform-burning matrix burner
    US-2006112675-A1June 01, 2006Honeywell International, Inc.Twisted mixer with open center body
    US-7682597-B2March 23, 2010Uhde GmbhMethod for extracting hydrogen from a gas that contains methane, especially natural gas, and system for carrying out said method
    US-8196387-B2June 12, 2012Praxair Technology, Inc.Electrical power generation apparatus
    US-7861511-B2January 04, 2011General Electric CompanySystem for recirculating the exhaust of a turbomachine
    US-2010126906-A1May 27, 2010Ken SuryProcess For Recovering Solvent From Ashphaltene Containing Tailings Resulting From A Separation Process
    US-6148602-ANovember 21, 2000Norther Research & Engineering CorporationSolid-fueled power generation system with carbon dioxide sequestration and method therefor
    US-6089855-AJuly 18, 2000Thermo Power CorporationLow NOx multistage combustor
    US-7934926-B2May 03, 2011Deka Products Limited PartnershipGaseous fuel burner
    US-4101294-AJuly 18, 1978General Electric CompanyProduction of hot, saturated fuel gas
    US-7931731-B2April 26, 2011Shell Oil CompanyProcess for production of elemental iron
    US-8453583-B2June 04, 2013Itea S.P.A.High-efficiency combustors with reduced environmental impact and processes for power generation derivable therefrom
    US-7089743-B2August 15, 2006AlstomMethod for operating a power plant by means of a CO2 process
    US-2003221409-A1December 04, 2003Mcgowan Thomas F.Pollution reduction fuel efficient combustion turbine
    US-6374591-B1April 23, 2002Tractebel Lng North America LlcLiquified natural gas (LNG) fueled combined cycle power plant and a (LNG) fueled gas turbine plant
    US-6993901-B2February 07, 2006Nissan Motor Co., Ltd.Excess air factor control of diesel engine
    US-7765810-B2August 03, 2010Precision Combustion, Inc.Method for obtaining ultra-low NOx emissions from gas turbines operating at high turbine inlet temperatures
    US-8046986-B2November 01, 2011General Electric CompanyMethod and system for controlling an exhaust gas recirculation system
    US-5084438-AJanuary 28, 1992Nec CorporationElectronic device substrate using silicon semiconductor substrate
    US-7752848-B2July 13, 2010General Electric CompanySystem and method for co-production of hydrogen and electrical energy
    US-8220247-B2July 17, 2012Membrane Technology And Research, Inc.Power generation process with partial recycle of carbon dioxide
    US-7503948-B2March 17, 2009Exxonmobil Research And Engineering CompanySolid oxide fuel cell systems having temperature swing reforming
    US-8117825-B2February 21, 2012Alstom Technology Ltd.Gas turbine installation
    US-8371100-B2February 12, 2013General Electric CompanySystem and method to generate electricity
    US-5359847-ANovember 01, 1994Westinghouse Electric CorporationDual fuel ultra-low NOX combustor
    US-4442665-AApril 17, 1984General Electric CompanyCoal gasification power generation plant
    US-8127936-B2March 06, 2012Uop LlcHigh performance cross-linked polybenzoxazole and polybenzothiazole polymer membranes
    US-8220248-B2July 17, 2012Membrane Technology And Research, IncPower generation process with partial recycle of carbon dioxide
    US-5771867-AJune 30, 1998Caterpillar Inc.Control system for exhaust gas recovery system in an internal combustion engine
    US-5085274-AFebruary 04, 1992Amoco CorporationRecovery of methane from solid carbonaceous subterranean of formations
    US-6826913-B2December 07, 2004Honeywell International Inc.Airflow modulation technique for low emissions combustors
    US-8316665-B2November 27, 2012Fluor Technologies CorporationIntegration of LNG regasification with refinery and power generation
    US-4018046-AApril 19, 1977Avco CorporationInfrared radiation suppressor for gas turbine engine
    WO-2013147633-A1October 03, 2013General Electric CompanyTurbomachine combustor assembly
    US-6790030-B2September 14, 2004The Regents Of The University Of CaliforniaMulti-stage combustion using nitrogen-enriched air
    US-2013086917-A1April 11, 2013Ilya Aleksandrovich Slobodyanskiy, Gilbert Otto Kraemer, Leonid Yul'evich Ginesin, Dmitry Vladlenovich Tretyakov, Andrey Pavlovich SubbotaApparatus for head end direct air injection with enhanced mixing capabilities
    US-2011232545-A1September 29, 2011Her Majesty The Queen In Right Of Canada As Represented By The Minister Of Natural ResourcesHigh Pressure Direct Contact Oxy-Fired Steam Generator
    US-2013269355-A1October 17, 2013General Electric CompanyMethod and system for controlling an extraction pressure and temperature of a stoichiometric egr system
    US-7077199-B2July 18, 2006Shell Oil CompanyIn situ thermal processing of an oil reservoir formation
    US-2001029732-A1October 18, 2001Rolf BachmannProcess for the recovery of water from the flue gas of a combined cycle power station, and combined cycle power station for performing the process
    US-2012096870-A1April 26, 2012General Electric CompanyCombined cycle power plant including a carbon dioxide collection system
    US-7536873-B2May 26, 2009Linde AktiengesellschaftProcess and device for cooling a gas by direct heat exchange with a cooling liquid
    US-2006112696-A1June 01, 2006Statoil AsaEfficient combined cycle power plant with co2 capture and a combustor arrangement with separate flows
    US-7284362-B2October 23, 2007L'Air Liquide, Société Anonyme à Directoire et Conseil de Surveillance pour l'Étude et l'Exploitation des Procedes Georges ClaudeIntegrated air separation and oxygen fired power generation system
    US-7520134-B2April 21, 2009General Electric CompanyMethods and apparatus for injecting fluids into a turbine engine
    US-5458481-AOctober 17, 1995Zeeco, Inc.Burner for combusting gas with low NOx production
    US-6923915-B2August 02, 2005Tda Research, Inc.Process for the removal of impurities from combustion fullerenes
    US-4165609-AAugust 28, 1979The Boeing CompanyGas turbine mixer apparatus
    US-2009107141-A1April 30, 2009General Electric CompanySystem for recirculating the exhaust of a turbomachine
    US-2008250795-A1October 16, 2008Conocophillips CompanyAir Vaporizer and Its Use in Base-Load LNG Regasification Plant
    US-2002043063-A1April 18, 2002Masaki Kataoka, Motoaki Utamura, Takaaki KuwaharaExhaust gas recirculation type combined plant
    US-8110012-B2February 07, 2012Alstom Technology LtdSystem for hot solids combustion and gasification
    US-8567200-B2October 29, 2013Peter Holroyd Brook, Geoffrey Frederick SkinnerProcess
    US-7734408-B2June 08, 2010Toyota Jidosha Kabushiki KaishaElectric parking brake system and method for controlling the electric parking brake system
    US-4895710-AJanuary 23, 1990Helge G. GranNitrogen injection
    US-5345756-ASeptember 13, 1994Texaco Inc.Partial oxidation process with production of power
    US-2011000671-A1January 06, 2011Frank Hershkowitz, Eric Nelson, Mcmahon PatrickLow Emission Power Generation and Hydrocarbon Recovery Systems and Methods
    US-7416137-B2August 26, 2008Vast Power Systems, Inc.Thermodynamic cycles using thermal diluent
    US-6298664-B1October 09, 2001Norsk Hydro AsaProcess for generating power including a combustion process
    US-2001045090-A1November 29, 2001Gray Charles L.Low emission, diesel-cycle engine
    WO-9707329-A1February 27, 1997University Of Massachusetts Medical CenterCentrale electrique avec recuperation du dioxyde de carbone
    US-2009223227-A1September 10, 2009General Electric CompanyCombustion cap with crown mixing holes
    US-2007000242-A1January 04, 2007Caterpillar Inc.Regeneration assembly
    US-2009000762-A1January 01, 2009Wilson Turbopower, Inc.Brush-seal and matrix for regenerative heat exchanger, and method of adjusting same
    US-2488911-ANovember 22, 1949Surface Combustion CorpCombustion apparatus for use with turbines
    WO-2012003076-A1January 05, 2012Exxonmobil Upstream Research CompanyProcédés et systèmes de génération d'électricité à trois cycles et à faible émission
    US-2005229585-A1October 20, 2005Webster John RGas turbine engine exhaust nozzle
    US-5359847-B1April 09, 1996Westinghouse Electric CorpDual fuel ultra-flow nox combustor
    US-6505567-B1January 14, 2003Alstom (Switzerland) LtdOxygen fired circulating fluidized bed steam generator
    CA-2614669-CDecember 30, 2008Imperial Oil Resources Limited, Ken SuryProcessus ameliore permettant de recuperer un solvant d'asphaltene contenant un refus resultant d'un procede de separation
    US-8029273-B2October 04, 2011Alstom Technology LtdBurner
    US-7363756-B2April 29, 2008Alstom Technology LtdMethod for combustion of a fuel
    US-2008115478-A1May 22, 2008Siemens Power Generation, Inc.System and method for generation of high pressure air in an integrated gasification combined cycle system
    US-5566756-AOctober 22, 1996Amoco CorporationMethod for recovering methane from a solid carbonaceous subterranean formation
    US-7299619-B2November 27, 2007Siemens Power Generation, Inc.Vaporization of liquefied natural gas for increased efficiency in power cycles
    US-7490472-B2February 17, 2009Statoil AsaEfficient combined cycle power plant with CO2 capture and a combustor arrangement with separate flows
    US-6598398-B2July 29, 2003Clean Energy Systems, Inc.Hydrocarbon combustion power generation system with CO2 sequestration
    US-5098282-AMarch 24, 1992John Zink CompanyMethods and apparatus for burning fuel with low NOx formation
    US-7059152-B2June 13, 2006The Boc Group PlcNitrogen rejection method and apparatus
    US-7506501-B2March 24, 2009Honeywell International Inc.Compact mixer with trimmable open centerbody
    US-7516626-B2April 14, 2009Linde AktiengesellschaftApparatus for the low-temperature separation of a gas mixture, in particular air
    US-6899859-B1May 31, 2005Den Norske Stats Oljeselskap A.S.Method for preparing a H2-rich gas and a CO2-rich gas at high pressure
    US-8038746-B2October 18, 2011Clark Steve LReduced-emission gasification and oxidation of hydrocarbon materials for liquid fuel production
    US-2013269357-A1October 17, 2013General Electric CompanyMethod and system for controlling a secondary flow system
    US-2011226010-A1September 22, 2011Brigham Young UniversityCarbon dioxide capture from flue gas
    US-2008127632-A1June 05, 2008General Electric CompanyCarbon dioxide capture systems and methods
    US-7143572-B2December 05, 2006Kawasaki Jukogyo Kabushiki KaishaGas turbine system comprising closed system of fuel and combustion gas using underground coal layer
    US-2008251234-A1October 16, 2008Wilson Turbopower, Inc.Regenerator wheel apparatus
    US-2008155984-A1July 03, 2008Ke Liu, Michael John Bowman, Stephen Duane Sanborn, Andrei Tristan EvuletReforming system for combined cycle plant with partial CO2 capture
    US-7410525-B1August 12, 2008Uop LlcMixed matrix membranes incorporating microporous polymers as fillers
    US-2010058732-A1March 11, 2010Peter Kaufmann, Werner KrebsCombustion chamber for a gas turbine
    US-7875402-B2January 25, 2011Exxonmobil Research And Engineering CompanyProton conducting solid oxide fuel cell systems having temperature swing reforming
    US-2009262599-A1October 22, 2009Heinrich Gillet Gmbh (Tenneco))Method for mixing an exhaust gas flow
    US-2008290719-A1November 27, 2008Kaminsky Robert D, Thomas Michele M, Lauren Blanton, Nelson Eric D, Symington William AProcess for producing Hydrocarbon fluids combining in situ heating, a power plant and a gas plant
    US-2008066443-A1March 20, 2008Alstom Technology LtdGas turbine plant for a working medium in the form of a carbon dioxide/water mixture
    US-2004238654-A1December 02, 2004Hagen David L., Gary Ginter, Alberto Traverso, Bill Goheen, Mcguire Allan, Janet Rankin, Aristide Massardo, Klaus Ronald L.Thermodynamic cycles using thermal diluent
    US-4548034-AOctober 22, 1985Rolls-Royce LimitedBypass gas turbine aeroengines and exhaust mixers therefor
    US-6615576-B2September 09, 2003Honeywell International Inc.Tortuous path quiet exhaust eductor system
    US-7874140-B2January 25, 2011Foster Wheeler North America Corp.Method of and power plant for generating power by oxyfuel combustion
    US-7043920-B2May 16, 2006Clean Energy Systems, Inc.Hydrocarbon combustion power generation system with CO2 sequestration
    US-2008000229-A1January 03, 2008Alfred Kuspert, Wolfram Schmid, Siegfried SumserInternal combustion engine having an exhaust gas turbocharge and an exhaust gas recirculation system
    US-4651712-AMarch 24, 1987Arkansas Patents, Inc.Pulsing combustion
    US-5457951-AOctober 17, 1995Cabot CorporationImproved liquefied natural gas fueled combined cycle power plant
    US-8436489-B2May 07, 2013Lightsail Energy, Inc.Compressed air energy storage system utilizing two-phase flow to facilitate heat exchange
    US-6810673-B2November 02, 2004United Technologies CorporationLow emissions combustor for a gas turbine engine
    US-5894720-AApril 20, 1999Capstone Turbine CorporationLow emissions combustion system for a gas turbine engine employing flame stabilization within the injector tube
    US-4043395-AAugust 23, 1977Continental Oil CompanyMethod for removing methane from coal
    US-7591866-B2September 22, 2009Ranendra BoseMethane gas recovery and usage system for coalmines, municipal land fills and oil refinery distillation tower vent stacks
    US-4434613-AMarch 06, 1984General Electric CompanyClosed cycle gas turbine for gaseous production
    US-8257476-B2September 04, 2012Air Products And Chemicals, Inc.Purification of carbon dioxide
    US-7788897-B2September 07, 2010Vast Power Portfolio, LlcLow emissions combustion apparatus and method
    US-8424282-B2April 23, 2013Alstom Technology Ltd.Combined-cycle power plant with exhaust gas recycling and CO2 separation, and method for operating a combined cycle power plant
    US-6461147-B1October 08, 2002Leiv Eiriksson Nyfotek AsGas Burner
    US-2013269358-A1October 17, 2013General Electric CompanyMethods, systems and apparatus relating to reheat combustion turbine engines with exhaust gas recirculation
    US-7401577-B2July 22, 2008American Air Liquide, Inc.Real time optimization and control of oxygen enhanced boilers
    US-2010322759-A1December 23, 2010Mitsubishi Heavy Industries, Ltd.Structure of exhaust section of gas turbine and gas turbine
    US-2007231233-A1October 04, 2007Ranendra BoseMethane gas recovery and usage system for coalmines, municipal land fills and oil refinery distillation tower vent stacks
    US-8414694-B2April 09, 2013Mitsubishi Heavy Industries, Ltd., The Kansai Electric Power Co., Inc.CO2 recovery apparatus and CO2 recovery method
    US-7634915-B2December 22, 2009General Electric CompanySystems and methods for power generation and hydrogen production with carbon dioxide isolation
    US-2009218821-A1September 03, 2009General Electric CompanyLow emission turbine system and method
    US-8117846-B2February 21, 2012Siemens AktiengesellschaftGas turbine burner and method of mixing fuel and air in a swirling area of a gas turbine burner
    US-2012023954-A1February 02, 2012General Electric CompanyPower plant and method of operation
    US-2003005698-A1January 09, 2003Conoco Inc.LNG regassification process and system
    GB-2397349-BSeptember 21, 2005Kawasaki Heavy Ind LtdGas turbine system
    US-8398757-B2March 19, 2013Mitsubishi Heavy Industries, Ltd., The Kansai Electric Power Co., Inc.CO2 recovering apparatus
    US-6490858-B2December 10, 2002Ashley J. Barrett, Bruce H. WoodrowCatalytic converter thermal aging method and apparatus
    US-6253555-B1July 03, 2001Rolls-Royce PlcCombustion chamber comprising mixing ducts with fuel injectors varying in number and cross-sectional area
    US-7562529-B2July 21, 2009Daimler AgInternal combustion engine having an exhaust gas turbocharger and an exhaust gas recirculation system
    WO-9521683-A1August 17, 1995Kværner Water Systems A.S.Procede pour eliminer et empecher les emissions dans l'atmosphere de dioxyde de carbone provenant des gaz d'echappement de moteurs thermiques
    US-7168488-B2January 30, 2007Statoil AsaMethod and plant or increasing oil recovery by gas injection
    US-7472550-B2January 06, 2009University Of Florida Research Foundation, Inc.Combined cooling and power plant with water extraction
    US-6101983-AAugust 15, 2000General Electric Co.Modified gas turbine system with advanced pressurized fluidized bed combustor cycle
    US-7670135-B1March 02, 2010Zeeco, Inc.Burner and method for induction of flue gas
    US-2010003123-A1January 07, 2010Smith Craig FInlet air heating system for a gas turbine engine
    US-2011239653-A1October 06, 2011General Electric CompanyAnnular ring-manifold quaternary fuel distributor
    US-7217303-B2May 15, 2007Exxonmobil Research And Engineering CompanyPressure swing reforming for fuel cell systems
    US-2012023958-A1February 02, 2012General Electric CompanyPower plant and control method
    US-7827778-B2November 09, 2010General Electric Company, StatoilPower plants that utilize gas turbines for power generation and processes for lowering CO2 emissions
    US-7143606-B2December 05, 2006L'air Liquide-Societe Anonyme A'directoire Et Conseil De Surveillance Pour L'etide Et L'exploitation Des Procedes Georges ClaudeCombined air separation natural gas liquefaction plant
    US-8133298-B2March 13, 2012Air Products And Chemicals, Inc.Blast furnace iron production with integrated power generation
    US-7559977-B2July 14, 2009Sargas AsPurification works for thermal power plant
    US-2006248888-A1November 09, 2006Behr Gmbh & Co. KgSystem for exhaust gas recirculation in a motor vehicle
    WO-2013147632-A1October 03, 2013General Electric CompanyCapot d'extrémité bidirectionnelle à capacité d'extraction pour dispositif combustor de turbine à gaz
    US-2012185144-A1July 19, 2012Samuel David DraperStoichiometric exhaust gas recirculation and related combustion control
    US-6644041-B1November 11, 2003Volker EyermannSystem in process for the vaporization of liquefied natural gas
    US-4271664-AJune 09, 1981Hydragon CorporationTurbine engine with exhaust gas recirculation
    US-2009056342-A1March 05, 2009General Electric CompanyMethods and Systems for Gas Turbine Part-Load Operating Conditions
    US-2013086916-A1April 11, 2013Russell H. Oelfke, Moses MintaLow Emission Power Generation Systems and Methods
    WO-2012128929-A2September 27, 2012Exxonmobil Upstream Research CompanySystèmes et procédés de production d'électricité à faibles émissions incluant la séparation du dioxyde de carbone
    US-6412559-B1July 02, 2002Alberta Research Council Inc.Process for recovering methane and/or sequestering fluids
    US-6505683-B2January 14, 2003Institut Francais Du PetroleProcess for purification by combination of an effluent that contains carbon dioxide and hydrocarbons
    US-8247462-B2August 21, 2012Sasol Technology (Proprietary) LimitedCo-production of power and hydrocarbons
    US-7988750-B2August 02, 2011Korea Advanced Institute Of Science And TechnologyMethod for recovering methane gas from natural gas hydrate
    US-7147461-B2December 12, 2006David Lloyd NearyPartially-open fired heater cycle providing high thermal efficiencies and ultra-low emissions
    US-6826912-B2December 07, 2004Yeshayahou LevyDesign of adiabatic combustors
    US-7137623-B2November 21, 2006Spx Cooling Technologies, Inc.Heating tower apparatus and method with isolation of outlet and inlet air
    US-2012023955-A1February 02, 2012General Electric CompanyPower plant and method of operation
    WO-2012018458-A1February 09, 2012Exxonmobil Upstream Research CompanySystem and method for exhaust gas extraction
    US-5638675-AJune 17, 1997United Technologies CorporationDouble lobed mixer with major and minor lobes
    US-2011048002-A1March 03, 2011Bha Group, Inc.turbine exhaust recirculation
    US-2013269311-A1October 17, 2013General Electric CompanySystems and apparatus relating to reheat combustion turbine engines with exhaust gas recirculation
    US-2007028774-A1February 08, 2007Board Of Regents, The University Of Texas SystemRegeneration of an aqueous solution from an acid gas absorption process by multistage flashing and stripping
    US-5956937-ASeptember 28, 1999Clean Energy Systems, Inc.Reduced pollution power generation system having multiple turbines and reheater
    WO-2009121008-A3January 07, 2010Exxonmobil Upstream Research CompanySystèmes et procédés de production d’énergie à faible taux d’émission et de récupération d’hydrocarbure
    US-2007089425-A1April 26, 2007General Electric CompanyMethods and systems for low emission gas turbine energy generation
    US-7040400-B2May 09, 2006Shell Oil CompanyIn situ thermal processing of a relatively impermeable formation using an open wellbore
    US-2008309087-A1December 18, 2008General Electric CompanySystems and methods for power generation with exhaust gas recirculation
    US-7467942-B2December 23, 2008Alstom Technology Ltd.Device and method for flame stabilization in a burner
    US-2011227346-A1September 22, 2011Ares Turbine AsGas turbine with external combustion, applying a rotating regenerating heat exchanger
    US-8266883-B2September 18, 2012General Electric CompanyPower plant start-up method and method of venting the power plant
    US-6945089-B2September 20, 2005Forschungszentrum Karlsruhe GmbhMass-sensitive sensor
    US-8539749-B1September 24, 2013General Electric CompanySystems and apparatus relating to reheat combustion turbine engines with exhaust gas recirculation
    US-7677309-B2March 16, 2010Statoil Asa, Petrosa (The Petroleum Oil & Gas Corporation Of Sa (Pty) Ltd)Method for increased oil recovery from an oil field
    US-2004006994-A1January 15, 2004Walsh Philip P., Paul FletcherGas turbine engine
    US-2008006561-A1January 10, 2008Moran Lyle E, Windsor Larry WDearomatized asphalt
    US-5195884-AMarch 23, 1993John Zink Company, A Division Of Koch Engineering Company, Inc.Low NOx formation burner apparatus and methods
    US-6389814-B1December 31, 1969
    US-2009025390-A1January 29, 2009Sargas AsLow CO2 Thermal Powerplant
    US-8167960-B2May 01, 2012Osum Oil Sands Corp.Method of removing carbon dioxide emissions from in-situ recovery of bitumen and heavy oil
    US-7043898-B2May 16, 2006Pratt & Whitney Canada Corp.Combined exhaust duct and mixer for a gas turbine engine
    US-7695703-B2April 13, 2010Siemens Energy, Inc.High temperature catalyst and process for selective catalytic reduction of NOx in exhaust gases of fossil fuel combustion
    US-7104784-B1September 12, 2006Nippon Furnace Kogyo Kaisha, Ltd.Device and method for feeding fuel
    US-7468173-B2December 23, 2008Sunstone CorporationMethod for producing nitrogen to use in under balanced drilling, secondary recovery production operations and pipeline maintenance
    US-7065953-B1June 27, 2006Enhanced Turbine Output HoldingSupercharging system for gas turbines
    US-6939130-B2September 06, 2005Gas Technology InstituteHigh-heat transfer low-NOx combustion system
    US-2005197267-A1September 08, 2005Troxler Electronics Laboratories, Inc.Solvent compositions for removing petroleum residue from a substrate and methods of use thereof
    US-8105559-B2January 31, 2012Johnson Matthey Public Limited CompanyThermally regenerable nitric oxide adsorbent
    US-2001000049-A1March 22, 2001Masaki Kataoka, Motoaki Utamura, Takaaki KuwaharaExhaust gas recirculation type combined plant
    US-8083474-B2December 27, 2011Tofuji E.M.I.Co., Ltd., Mitsubishi Heavy Industries, Ltd.Turbocharger
    US-8001789-B2August 23, 2011Alstom Technologies Ltd., LlcUtilizing inlet bleed heat to improve mixing and engine turndown
    US-2009193809-A1August 06, 2009Mark Stewart Schroder, Mark Allan Hadley, Depuy Richard Anthony, Todd Stanley NemecMethod and system to facilitate combined cycle working fluid modification and combustion thereof
    US-2007044475-A1March 01, 2007Stefan Leser, Michael Kaatz, Miroslav PodhorskyExhaust gas guide of a gas turbine and method for mixing the exhaust gas of the gas turbine
    US-2010300102-A1December 02, 2010General Electric CompanyMethod and apparatus for air and fuel injection in a turbine
    US-6655150-B1December 02, 2003Norsk Hydro AsaMethod for removing and recovering CO2 from exhaust gas
    US-8245492-B2August 21, 2012General Electric CompanyPower plant and method of operation
    US-8127937-B2March 06, 2012Uop LlcHigh performance cross-linked polybenzoxazole and polybenzothiazole polymer membranes
    US-5304362-AApril 19, 1994Abb Carbon AbMethod in cleaning flue gas in a PFBC plant including a gas turbine driven thereby
    US-5709077-AJanuary 20, 1998Clean Energy Systems, Inc.Reduce pollution hydrocarbon combustion gas generator
    US-7914749-B2March 29, 2011Solid Gas TechnologiesClathrate hydrate modular storage, applications and utilization processes
    US-7194869-B2March 27, 2007Siemens Power Generation, Inc.Turbine exhaust water recovery system
    US-6868677-B2March 22, 2005Clean Energy Systems, Inc.Combined fuel cell and fuel combustion power generation systems
    US-2010018218-A1January 28, 2010Riley Horace E, Boyd Thomas EPower plant with emissions recovery
    US-2012192565-A1August 02, 2012General Electric CompanySystem for premixing air and fuel in a fuel nozzle
    US-7074033-B2July 11, 2006David Lloyd NearyPartially-open fired heater cycle providing high thermal efficiencies and ultra-low emissions
    US-2011126512-A1June 02, 2011Honeywell International Inc.Turbofan gas turbine engine aerodynamic mixer
    CA-2550675-A1July 14, 2005Alstom Technology Ltd, Dominikus Buecker, Timothy Griffin, Dieter WinklerCentrale thermique a combustion sequentielle et a rejets reduits de co<sb>2 </sb>et procede de fonctionnement associe
    US-2008047280-A1February 28, 2008Bhp Billiton LimitedHeat recovery system
    US-7753972-B2July 13, 2010Pioneer Energy, IncPortable apparatus for extracting low carbon petroleum and for generating low carbon electricity
    US-2012131925-A1May 31, 2012Exxonmobil Upstream Research CompanyCombustor systems and methods for using same
    US-2009205334-A1August 20, 2009General Electric CompanySystems and Methods for Exhaust Gas Recirculation (EGR) for Turbine Engines
    US-7611681-B2November 03, 2009Alstom Technology LtdProcess for the regeneration of a catalyst plant and apparatus for performing the process
    US-7566394-B2July 28, 2009Saudi Arabian Oil CompanyEnhanced solvent deasphalting process for heavy hydrocarbon feedstocks utilizing solid adsorbent
    US-7032388-B2April 25, 2006General Electric CompanyMethod and system for incorporating an emission sensor into a gas turbine controller
    US-7673454-B2March 09, 2010Mitsubishi Heavy Industries, Ltd.Combustor of gas turbine and combustion control method for gas turbine
    US-2006196812-A1September 07, 2006Beetge Jan H, Petrus Johannes Venter, Wang Sanyi, Xiaoli Yang, Yicheng Long, Yuming Xu, Tadeusz Dabros, Hassan HamzaZone settling aid and method for producing dry diluted bitumen with reduced losses of asphaltenes
    US-2009301099-A1December 10, 2009Nello NigroPower Generation
    WO-2012003079-A1January 05, 2012Exxonmobil Upstream Research CompanyStoichiometric combustion of enriched air with exhaust gas recirculation
    US-7007487-B2March 07, 2006Mes International, Inc.Recuperated gas turbine engine system and method employing catalytic combustion
    US-2003131582-A1July 17, 2003Anderson Roger E., Harry Brandt, Fermin ViteriCoal and syngas fueled power generation systems featuring zero atmospheric emissions
    US-2002069648-A1June 13, 2002Yeshayahou LevyNovel design of adiabatic combustors
    US-2002187449-A1December 12, 2002Klaus Doebbeling, Bettina Paikert, Paschereit Christian OliverBurner with exhaust gas recirculation
    US-5743079-AApril 28, 1998Rolls-Royce PlcTurbine engine control system
    US-8191360-B2June 05, 2012Lightsail Energy, Inc.Compressed air energy storage system utilizing two-phase flow to facilitate heat exchange
    US-7438744-B2October 21, 2008Eco/Technologies, LlcMethod and system for sequestering carbon emissions from a combustor/boiler
    US-7886522-B2February 15, 2011Kammel RefaatDiesel gas turbine system and related methods
    US-2004223408-A1November 11, 2004Peter Mathys, Robert Schaetti, Zdravko MandicStatic mixer
    US-7485761-B2February 03, 2009Basf AktiengesellschaftMethod for producing 1-butene
    US-2009071166-A1March 19, 2009Hagen David L, Gary Ginter, Alberto Traverso, Bill Goheen, Mcguire Allan, Janet Rankin, Aristride Massardo, Klaus Ronald LThermodynamic cycles using thermal diluent
    US-2009301054-A1December 10, 2009Simpson Stanley F, Gilchrist George M, Hasan KarimTurbine system having exhaust gas recirculation and reheat
    US-7492054-B2February 17, 2009Catlin Christopher SRiver and tidal power harvester
    US-2012119512-A1May 17, 2012General Electric CompanyPower plant and method of operation
    US-8034166-B2October 11, 2011Basf SeCarbon dioxide absorbent requiring less regeneration energy
    US-7481048-B2January 27, 2009Caterpillar Inc.Regeneration assembly
    US-7819951-B2October 26, 2010Air Products And Chemicals, Inc.Purification of carbon dioxide
    US-7610752-B2November 03, 2009Eaton CorporationDevices and methods for reduction of NOx emissions from lean burn engines
    US-8337613-B2December 25, 2012Bert ZaudererSlagging coal combustor for cementitious slag production, metal oxide reduction, shale gas and oil recovery, enviromental remediation, emission control and CO2 sequestration
    US-7955403-B2June 07, 2011Kellogg Brown & Root LlcSystems and methods for producing substitute natural gas
    US-7845406-B2December 07, 2010George NitschkeEnhanced oil recovery system for use with a geopressured-geothermal conversion system
    US-6772583-B2August 10, 2004Siemens Westinghouse Power CorporationCan combustor for a gas turbine engine
    US-2011110759-A1May 12, 2011General Electric CompanyMethod and system for reducing the impact on the performance of a turbomachine operating an extraction system
    US-2005028529-A1February 10, 2005Bartlett Michael Adam, Timothy Griffin, Daniel HolmbergMethod of generating energy in a power plant comprising a gas turbine, and power plant for carrying out the method
    WO-9963210-A1December 09, 1999Aker EngineeringCentrale electrique amelioree equipee d'un dispositif de capture du dioxyde de carbone
    US-5355668-AOctober 18, 1994General Electric CompanyCatalyst-bearing component of gas turbine engine
    US-6247315-B1June 19, 2001American Air Liquids, Inc., L'air Liquide, Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges ClaudeOxidant control in co-generation installations
    US-6429020-B1August 06, 2002The United States Of America As Represented By The United States Department Of EnergyFlashback detection sensor for lean premix fuel nozzles
    US-6732531-B2May 11, 2004Capstone Turbine CorporationCombustion system for a gas turbine engine with variable airflow pressure actuated premix injector
    US-2009284013-A1November 19, 2009General Electric CompanyDry 3-way catalytic reduction of gas turbine NOx

NO-Patent Citations (54)

    Title
    Ahmed, S. et al. (1998) "Catalytic Partial Oxidation Reforming of Hydrocarbon Fuels," 1998 Fuel Cell Seminar, Nov. 16-19, 1998, 7 pgs.
    Air Separation Technology Ion Transport Membrane-Air Products 2008.
    Air Separation Technology Ion Transport Membrane-Air Products 2011.
    Anderson, R. E. (2006) "Durability and Reliability Demonstration of a Near-Zero-Emission Gas-Fired Power Plant," California Energy Comm., CEC 500-2006-074, 80 pgs.
    Baxter, E. et al. (2003) "Fabricate and Test an Advanced Non-Polluting Turbine Drive Gas Generator," U. S. Dept. of Energy, Nat'l Energy Tech. Lab., DE-FC26-00NT 40804, 51 pgs.
    Bolland, O. et al. (1998) "Removal of CO2 From Gas Turbine Power Plants Evaluation of Pre- and Postcombustion Methods," SINTEF Group, 1998, www.energy.sintef.no/publ/xergi/98/3/art-8engelsk.htm, 11 pgs.
    BP Press Release (2006) "BP and Edison Mission Group Plan Major Hydrogen Power Project for California," Feb. 10, 2006, www.bp.com/hydrogenpower, 2 pgs.
    Bryngelsson, M. et al. (2005) "Feasibility Study of CO2 Removal From Pressurized Flue Gas in a Fully Fired Combined Cycle-The Sargas Project," KTH-Royal Institute of Technology, Dept. of Chemical Engineering and Technology, 9 pgs.
    Cho, J. H. et al. (2005) "Marrying LNG and Power Generation," Energy Markets; Oct./Nov. 2005; 10, 8; ABI/INFORM Trade & Industry, p. 28.
    Ciulia, Vincent. About.com. Auto Repair. How the Engine Works. 2001-2003.
    Clark, Hal (2002) "Development of a Unique Gas Generator for a Non-Polluting Power Plant," California Energy Commission Feasibility Analysis, P500-02-011F, Mar. 2002, 42 pgs.
    Corti, A. et al. (1988) "Athabasca Mineable Oil Sands: The RTR/Gulf Extraction Process Theoretical Model of Bitumen Detachment," 4th UNITAR/UNDP Int'l Conf. on Heavy Crude and Tar Sands Proceedings, v.5, paper No. 81, Edmonton, AB, Canada, Aug. 7-12, 1988, pp. 41-44.
    Cryogenics. Science Clarified. 2012. http://www.scienceclarified.com/Co-Di/Cryogenics.html.
    Defrate, L. A. et al. (1959) "Optimum Design of Ejector Using Digital Computers" Chem. Eng. Prog. Symp. Ser., 55 ( 21) pp. 46.
    Ditaranto, et al. , (2006), "Combustion Instabilities in Sudden Expansion Oxy-Fuel Flames," ScienceDirect, Combustion and Flame, v. 146, Jun. 30, 2006, 15 pgs.
    Elwell, L. C. et al. (2005) "Technical Overview of Carbon Dioxide Capture Technologies for Coal-Fired Power Plants," MPR Associates, Inc., Jun. 22, 2005, 15 pgs.
    Eriksson, Sara. Licentiate Thesis 2005, p. 22. KTH-"Development of Methane Oxidation Catalysts for Different Gas Turbine Combustor Concepts." The Royal Institute of Technology, Department of Chemical Engineering and Technology, Chemical Technology, Stockholm Sweden.
    Ertesvag, I. S. et al. (2005) "Energy Analysis of a Gas-Turbine Combined-Cycle Power Plant With Precombustion CO2 Capture," Elsivier, 2004, pp. 5-39.
    Evulet, Andrei T. et al. "Application of Exhaust Gas Recirculation in a DLN F-Class Combustion System for Postcombustion Carbon Capture" ASME J. Engineering for Gas Turbines and Power, vol. 131, May 2009.
    Evulet, Andrei T. et al. "On the Performance and Operability of GE's Dry Low Nox Combustors utilizing Exhaust Gas Recirculation for Post-Combustion Carbon Capture" Energy Procedia I 2009, 3809-3816.
    Foy, Kirsten et al. (2005) "Comparison of Ion Transport Membranes"-Fourth Annual Conference on Carbon Capture and Sequestration, DOE/NETL; May 2005, 11 pages.
    http://www.turbineinletcooling.org/resources/papers/CTIC-WetCompression-Shepherd-ASMETurboExpo2011.pdf , Shepherd, IGTI 2011-CTIC Wet Compression, Jun. 8th, 2011.
    Luby, P. et al. (2003) "Zero Carbon Power Generation: IGCC as the Premium Option," Powergen International, 19 pgs.
    MacAdam, S. et al. (2008) "Coal-Based Oxy-Fuel System Evaluation and Combustor Development," Clean Energy Systems, Inc. 6 pgs.
    Morehead, H. (2007) "Siemens Global Gasification and IGCC Update," Siemens, Coal-Gen, Aug. 3, 2007, 17 pgs.
    Nanda, R. et al. (2007) "Utilizing Air Based Technologies as Heat Source for LNG Vaporization," presented at the 86th Annual convention of the Gas Processors of America (GPA 2007), Mar. 11-14, 2007, San Antonio, TX.
    PCT/RU2013/000162, Feb. 28, 2013, General Electric Company.
    PCT/US13/036020, Apr. 10, 2013, General Electric Company/ExxonMobil Upstream Company.
    Reeves, S. R. (2001) "Geological Sequestration of CO2 in Deep, Unmineable Coalbeds: An Integrated Research and Commercial-Scale Field Demonstration Project," SPE 71749, 10 pgs.
    Reeves, S. R. (2003) "Enhanced Coalbed Methane Recovery," SPE 101466-DL, 8 pgs.
    Richards, G. A. et al. (2001) "Advanced Steam Generators," National Energy Technology Laboratory, 7 pgs.
    Rosetta, M. J. et al. (2006) "Integrating Ambient Air Vaporization Technology with Waste Heat Recovery-A Fresh Approach to LNG Vaporization," presented at the 85th annual convention of the Gas Processors of America (GPA 2006), Grapevine, Texas, Mar. 5-8, 2006.
    Snarheim, D. et al. (2006) "Control Design for a Gas Turbine Cycle With CO2 Capture Capabilities," Modeling, Identification and Control, vol. 00, 10 pgs.
    U.S. Appl. No. 13/596,684, filed Aug. 28, 2012, Slobodyanskiy et al.
    U.S. Appl. No. 14/066,488, filed Oct. 29, 2013, Pramod K. Biyani et al.
    U.S. Appl. No. 14/066,551, filed Oct. 29, 2013, Minto.
    U.S. Appl. No. 14/066,579, filed Oct. 29, 2013, Huntington et al.
    U.S. Appl. No. 14/067,486, filed Oct. 30, 2013, Huntington et al.
    U.S. Appl. No. 14/067,537, filed Oct. 30, 2013, Huntington et al.
    U.S. Appl. No. 14/067,552, filed Oct. 30, 2013, Huntington et al.
    U.S. Appl. No. 14/067,559, filed Oct. 30, 2013, Lucas John Stoia et al.
    U.S. Appl. No. 14/067,563, filed Oct. 30, 2013, Huntington et al.
    U.S. Appl. No. 14/067,679, filed Oct. 30, 2013, Elizabeth Angelyn Fadde et al.
    U.S. Appl. No. 14/067,714, filed Oct. 30, 2013, Carolyn Ashley Antoniono et al.
    U.S. Appl. No. 14/067,726, filed Oct. 30, 2013, Carolyn Ashley Antoniono et al.
    U.S. Appl. No. 14/067,731, filed Oct. 30, 2013, Carolyn Ashley Antoniono et al.
    U.S. Appl. No. 14/067,739, filed Oct. 30, 2013, Carolyn Ashley Antoniono et al.
    U.S. Appl. No. 14/067,797, filed Oct. 31, 2013, Anthony Wayne Krull et al.
    U.S. Appl. No. 14/067,844, filed Oct. 30, 2013, John Farrior Woodall et al.
    U.S. Appl. No. 14/135,055, filed Dec. 19, 2013, Pramod K. Biyani et al.
    U.S. Appl. No. 14/144,511, filed Dec. 30, 2013, Thatcher et al.
    Ulfsnes, R. E. et al. (2003) "Investigation of Physical Properties for CO2/H2O Mixtures for use in Semi-Closed O2/CO2 Gas Turbine Cycle With CO2-Capture," Department of Energy and Process Eng., Norwegian Univ. of Science and Technology, 9 pgs.
    vanHemert, P. et al. (2006) "Adsorption of Carbon Dioxide and a Hydrogen-Carbon Dioxide Mixture," Intn'l Coalbed Methane Symposium (Tuscaloosa, AL) Paper 0615, 9 pgs.
    Zhu, J. et al. (2002) "Recovery of Coalbed Methane by Gas Injection," SPE 75255, 15 pgs.

Cited By (2)

    Publication numberPublication dateAssigneeTitle
    US-2014250908-A1September 11, 2014Exxonmobil Upsteam Research Company, Georgia Tech Research CorporationSystems and Methods for Controlling Combustion of a Fuel
    US-2014290264-A1October 02, 2014Alstom Technology LtdControl of the gas composition in a gas turbine power plant with flue gas recirculation