Cogeneration system for co 2 letdown

Abstract

Cogeneration processes and systems for producing a gaseous CO2 product from a dense CO2 source. The process comprises utilizing hot exhaust gas from a gas turbine to preheat the dense CO2 source, expanding the preheated dense CO2 source, and recovering a gaseous CO2 product. The gaseous CO2 product may be transported in preexisting pipelines for which the dense CO2 exceeds the maximum allowable operating pressure.

Description

1001911.007701COGENERATION SYSTEM FOR CO2 LETDOWNFIELD

[0001] The present disclosure generally relates to the field of letdown stations and systems for cogeneration of power from adjacent gas turbine(s) and letdow n station(s).BACKGROUND

[0002] Carbon dioxide (CO2) is a widely used compound in a number of industries. In some situations, CO2 is used as a starting or intermediate material in chemical reactions. In other situations, CO2is used as a material in metalworking, oil and gas industries, agriculture, food sciences, etc.

[0003] Regardless of its intended use, it is ty pically necessary to transport large volumes of CO2 across large distances. CO2 transportation usually take the form of pipeline transportation. In certain configurations, CChis compressed to form a dense (e.g., liquid or supercritical liquid) CO2. Dense CO2 allows for the transportation of a higher volume of CO2. However, the pipeline and equipment (e.g., pumps) must be specifically designed to transport this dense CO2 phase.

[0004] Due to the specific requirements of transporting dense CO2, it is sometimes impossible to transport dense CChin certain currently existing pipelines not originally designed for such conditions. That is, existing pipelines (e.g.. natural gas or crude oil) may have a maximum allowable operating pressure (MAOP) below the dense CO2 phase conditions. In this situation, a "letdow n" of the dense CO2 phase into a gaseous CO2 falling below' the MAOP of the pipeline is required. This letdown process is particularly important when the dense CO2 is transitioned to an existing pipeline not rated (i.e. not having a MAOP) to handle the dense CO2.

[0005] A need exists in the industry for improved and more energy efficient processes and systems for the letdown of CO2 from the dense phase to the gaseous phase. Particularly, there is a need for such a letdown of CO2 while minimizing the external energy costs to such a letdown system.1CORE / 1001911.007701 / 233158072.11001911.007701BRIEF SUMMARY

[0006] One aspect of the present disclosure is directed to a process for producing a gaseous CO2 product. The process comprises providing a source of dense CO2 and a source of hot combustion gas; contacting the dense CO2 and the hot combustion gas in a first heat exchanger, thereby producing a preheated dense CO2 stream and a cooled combustion gas; expanding the preheated dense CO2 stream in a turbo-expander and / or control valve to produce an expanded CO2 stream; and contacting the expanded CO2 stream and the cooled combustion gas in a second heat exchanger, thereby heating the expanded CO2 stream and producing a gaseous CO2 product.

[0007] Another aspect of the present disclosure is directed to a system for producing a CO2 product. The system comprises a source of dense CO2 and a source of hot combustion gas; a first heat exchanger configured to heat the dense CO2 with the hot combustion gas and produce a preheated dense CO2 stream and a cooled combustion gas; a turbo-expander and / or control valve for expanding the preheated dense CO2 stream to produce an expanded CO2 stream; and a second heat exchanger for heating the expanded CO2 stream from the cooled combustion gas and producing a gaseous CO2 product.

[0008] In certain aspects, the hot combustion gas is the exhaust gas of a gas turbine and the gas turbine is adjacent to the first heat exchanger, turbo-expander, control valve, and / or second heat exchanger.

[0009] Other objects and features will be in part apparent and in part pointed out hereinafter.BRIEF DESCRIPTION OF THE FIGURES

[0010] Figure 1 illustrates an exemplary gas turbine system.

[0011] Figure 2A illustrates an exemplary gas turbine system comprising a heat recovery steam generator (HRSG).

[0012] Figure 2B illustrates an exemplary gas turbine system comprising a regeneration heat recovery design.

[0013] Figure 3 illustrates one embodiment of a gas turbine and letdown station design of the present invention comprising preheating of the dense CO2.

[0014] Figure 4A illustrates the process flow of the system of Figure 3.

[0015] Figure 4B is a phase change diagram corresponding to the system of Figure 3.2CORE / 1001911.007701 / 233158072.11001911.007701

[0016] Figure 5 illustrates another embodiment of a gas turbine and letdown station design of the present invention comprising preheating the dense CO2 and post-heating of the expanded CO2.

[0017] Figure 6A illustrates the process flow of the system of Figure 5.

[0018] Figure 6B is a phase change diagram corresponding to the system of Figure 5.

[0019] Figure 7 illustrates a further embodiment of the gas turbine and letdown station design of the present invention comprising preheating the dense CO2 and post-heating of the expanded dense CO2, wherein the letdown station comprises a turbo-expander.

[0020] Figure 8A illustrates the process flow of the system of Figure 7.

[0021] Figure 8B is a phase change diagram corresponding to the system of Figure 7.

[0022] Figure 9 shows a system similar to that of Figure 7, wherein at least a portion of the CO2 present in the exhaust gas is recovered and introduced into the dense CO2 stream.

[0023] Figure 10 shows a system similar to that of Figure 7, wherein at least a portion of the CO2 present in the exhaust gas is recovered and introduced into the gaseous CO2 product.

[0024] Figure 11 illustrates a typical phase diagram of pure CO2.

[0025] Figure 12 illustrate a phase diagram for various streams of CO2 containing impurities or additives.

[0026] Corresponding reference characters indicate corresponding parts throughout the drawings.DETAILED DESCRIPTION

[0027] The present invention is directed to the letdown of CO2 from the dense phase to the gaseous phase. Particularly, the present invention is directed to a process for producing a gaseous CO2 product from a dense CO2, while utilizing energy and / or heat that is present near the letdown station to minimize the overall energy costs of the letdow n. As used herein, the term "letdown station" is intended to refer to the one or more devices required to letdown the CO2 from the dense phase to the gaseous phase. As described elsewhere herein, this may entail the use of one or more heat exchangers, one or more control valves, and / or one or more turbo-expanders.

[0028] While dense CChis an efficient state to transport CO2 (i.e. a larger volume of CChmay be transported), the pipeline and associated equipment must be designed for such a3CORE / 1001911.007701 / 233158072.11001911.007701dense phase CO2. For example, the pipeline may need to be able to withstand and transport dense CO2 at or above the critical point. For example, dense CO2 at a pressure above the critical pressure (e.g., 1,150 psig or greater) and a temperature of between O F and 120 F.

[0029] The use of existing pipelines (e.g., natural gas pipelines) is an efficient way to transport CO2. However, these existing pipelines may not be rated or well positioned to transport CO2 when it is in the dense phase. One solution to this problem is to transport the CO2in the dense phase where possible, but to "letdown" the CO2from the dense phase to the gaseous phase when transitioning to a pipeline that is only be able to safely transport CO2 in the gaseous phase. In other embodiments, a letdown station wherein this phase change occurs can take place adjacent to a source of dense CO2 prior to introduction into a pipeline suitable for transporting gaseous CO2. Still further, a letdown station as described herein may be used at the outlet of the dense CO2 pipeline wherein a gaseous CO2 product is desired.

[0030] Certain embodiments of the present invention are directed to a process or system wherein a gaseous CO2 product is produced from combining a source of dense CO2 and a hot fluid or gas to form a preheated dense CO2 stream, expanding the preheated dense CO2 stream in a turbo-expander and / or control valve to produce an expanded CO2 stream. In some embodiments, this expanded CO2 stream is a gaseous CO2 product. In other embodiments, the expanded CO2 stream is further heated to produce a gaseous CO2 product.

[0031] In some embodiments the hot fluid or gas may be a hot combustion gas. For example, a hot combustion gas resulting from a gas turbine.

[0032] As illustrated in Figure 1, an exemplary gas turbine comprises a compressor (C), combustion chamber (CC), turbine (T), and generator (G). Air is introduced to the compressor at stream 1, compressed, and introduced as stream 2 into the combustion chamber. Simultaneously, a gas fuel is introduced to the combustion chamber as stream 5. The resulting combustion gas stream 3 is directed to the turbine-generator to produce power. A hot combustion gas 4 is removed from the gas turbine system.

[0033] In certain embodiments, the hot combustion gas may be removed from the system and used in a heat recovery’ steam generator (HRSG) as shown in Figure 2A. The gas turbine is shown as System A, and a HRSG system is shown as System B. Streams 1, 2, 3, and 4 are as discussed in Figure 1. In the process of Figure 2A, the gas fuel is methane. The resulting hot combustion gas 4 may be used in an air preheater (APH) to preheat the compressed air stream 2 prior to introduction into the combustion chamber. The hot4CORE / 1001911.007701 / 233158072.11001911.007701combustion gas is then directed to a HRSG system where steam is produced from the latent heat of the hot combustion gas and the remaining hot combustion gas is removed from the HRSG system as stream 6. An alternative heat recovery design (i.e. "regeneration") is shown in Figure 2B.

[0034] In either configuration (i.e. Figure 1, 2A, or 2B), the hot combustion gas 4 or 6 may be used as described herein as a source of heat for the process.

[0035] The letdown of gaseous CO2 (i.e. transition of a dense CO2 source to a gaseous CO2) requires a phase change of the CO2. This may be accomplished by increasing the temperature, decreasing the pressure, or a combination of both increasing the temperature and decreasing the pressure of the dense CO2. The phase change is complicated by the fact that dense CO2 is frequently present as a supercritical fluid and / or as a non-pure CO2 stream, such as a mixture of CO2 and water. When conducting the phase change it is desirable to avoid the phase mixture envelope (i.e. wherein two or more phases are present) for any significant amount of time and to avoid the so-called "water line" of the CO2 phase chart wherein water condenses. Water in a gaseous pipeline presents a number of possible problems, including pipeline corrosion and integrity issues.

[0036] A typical letdown station is designed to flash a dense phase product (e g., dense CO2) to a vapor phase product (e.g., gaseous CO2). This flashing may be accomplished by using a control valve, a turbo-expander, or any other suitable device. During this process, the temperature will drop due to Joule-Thompson cooling effect. That is, the temperature will be reduced during this flashing regardless of whether it was an intended aspect of the letdown station to cool the dense product. Without accounting for this effect, the process may unintentionally interact with the phase mixture envelop and / or water line.

[0037] The inventors have found that preheating the dense CO2 prior to introduction into the turbo-expander and / or control valve may help avoid these problems when converting the dense CO2 phase to a gaseous CO2 product. One aspect of the present invention is the use of hot turbine gas in the preheating step. For example, as illustrated in Figure 3.

[0038] Figure 3 illustrates a gas turbine and heat regeneration design similar to that of Figure 2B. The hot stream 107 leaving the regenerator HX-T is contacted with an inlet dense phase CO2 stream 110 in a heat exchanger. The resulting stream 111 is a preheated dense CO2 stream. The preheated dense CO2 stream is then flashed in a control valve to produce a5CORE / 1001911.007701 / 233158072.11001911.007701gaseous CO2 stream 112. Optionally, the hot exhaust gas 108 resulting from the heat exchange with the dense CO2 stream may be vented to a stack tower.

[0039] Figure 4A and 4B shows the process and phase change diagrams of the embodiment of Figure 3.

[0040] Figure 4A shows the steps of the process wherein dense CO2 is heated (1), depressurized using a control valve (2) and a gaseous CO2 product is produced (3). Figure 4B illustrates the pressure and temperature changes corresponding to this phase change.Operating in this manner avoids the issues attendant with the phase envelop and water line.

[0041] A second embodiment of the present invention is directed to preheating the dense phase CO2 stream, as described in detail above, and further heating the expanded CO2 stream resulting from the control valve. For example, as illustrated in Figure 5.

[0042] Similar to the above embodiment. Figure 5 details a gas turbine and heat regeneration design noted by reference numbers 201-207. The hot stream 207 leaving the regenerator HX-T is contacted with an inlet dense phase CO2 stream 210 in a heat exchanger. The resulting stream 211 is a preheated dense CO2 stream. The preheated dense CO2 stream is then flashed in a control valve to produce an expanded CO2 stream 212. The hot stream 208 exiting the first heat exchanger is then contacted with the expanded CO2 stream 212 in a second heat exchanger. The resulting stream 213 is a gaseous CO2 product. Optionally, the hot exhaust gas 209 resulting from the heat exchange with the dense CO2 stream may be vented to a stack tower.

[0043] Figure 6A and Figure 6B show the process and phase change diagrams of the embodiment of Figure 5.

[0044] As shown in Figure 6A, the dense CO2 stream is heated in a "Heating 1" step (i.e. first heat exchanger), depressurized to form an expanded CO2 stream, and the expanded CO2 stream is then heated in a "Heating 2" step (i.e. second heat exchanger) to produce the gaseous CO2 product.

[0045] As illustrated in Figure 6B, this design allows for the CO2 to avoid the phase envelop and water line for the duration of the process.

[0046] A further embodiment is illustrated in Figure 7. The process of Figure 7 is similar to that of Figure 5, except that the process of Figure 7 utilizes a turbo-expander in place of a control valve to flash the preheated dense CO2.6CORE / 1001911.007701 / 233158072.11001911.007701

[0047] Figure 8A and Figure 8B show the process and phase change diagrams of the embodiment of Figure 7.

[0048] Still further embodiments are directed to the removal of at least a portion of the carbon dioxide present in the hot gas turbine exhaust gas and incorporation of at least a portion of this removed carbon dioxide into the dense CO2 stream and / or into the gaseous CO2 product.

[0049] For example. Figure 9 shows a process similar to that of Figure 7. However, Figure 9 utilizes a CO2 removal step wherein at least a portion of the CO2 present in stream 309 is removed and introduced into the dense CO2 stream 310.

[0050] Figure 10 illustrates a process similar to that of Figure 7. However, Figure 10 utilizes a CO2 removal step wherein at least a portion of the CO2 present in stream 309 is removed and introduced into the gaseous CO2 product 313.

[0051] As illustrated in the above embodiments, it is one aspect of the present invention to employ energy saving processes and / or systems wherein hot combustion gas is recovered for use in preheating and / or post-heating a CO2 stream. In one embodiment, at least a portion of the hot combustion gas is the exhaust gas of a gas turbine. In other embodiments, the hot combustion gas is the exhaust gas of a gas turbine.

[0052] In certain embodiments of the present invention it is important to utilize a hot combustion gas that is adjacent to the letdown station (i.e. turbo-expander and / or control valve and associated equipment). That is, hot combustion gas is recovered on-site from other equipment / processes and directed for the preheating and / or post-heating a CO2 stream.Although discussion herein is primarily directed to the use of a hot gas turbine exhaust gas, it is possible to use any hot gas adjacent to the letdown station that is capable of preheating and / or post-heating a CO2 stream as described herein. In one embodiment, a gas turbine is adjacent to the letdown station and at least a portion of the hot combustion gas used to heat the CO2 is the exhaust gas of the gas turbine. For example, the gas turbine may be within 2,000 m or less, 1,500 m or less, 1,000 m or less, 500 m or less, 250 m or less, 100 m or less, 75 m or less, 50 m or less, 25 m or less of the letdown station (e.g., the first heat exchanger, turbo-expander, control valve, and / or second heat exchanger, etc.). In other embodiments, it is important for the source of hot exhaust gas to be adjacent to the first heat exchanger of the letdow n station to maximize the heat transfer. For example, in one embodiment, the gas7CORE / 1001911.007701 / 233158072.11001911.007701turbine is within 2,000 m or less, 1,500 m or less, 1,000 m or less, 500 m or less, 250 m or less, 100 m or less. 75 m or less. 50 m or less, 25 m or less of the first heat exchanger.

[0053] A phase diagram of pure CO2 is shown in Figure 11. At the triple point, CO2 can exist as any one of three phases (i.e. solid, liquid, or gas). This triple point for pure CO2 is at approximately 5.2 bar and -56°C (i.e. 75.42 psig and -68.8 °F). At the critical point, CO2 enters the "supercritical" phase where the CO2 has the density of a liquid but the viscosity of a gas. The critical point for pure CO2 is at approximately 74 bar and 31°C (i.e. 1,073.28 psig and 87.8 °F). The supercritical phase is achieved where the CO2 meets both the critical pressure and critical temperature. The critical pressure is the pressure above which liquid and gas phases cannot be distinguished. The critical temperature is the temperature at which the critical pressure is achieved. The region above the critical temperature and critical pressure is labeled the "supercritical region" (as shown in Figure 11), while the region above the critical pressure, but below the critical temperature, is called the "dense phase region." In the supercritical region, increases in pressure no longer produces a liquid, so long as the temperature exceeds the critical temperature. In the dense phase region, CO2 density increases with decreasing temperature.

[0054] While values for the triple point and critical point of pure CO2 have been provided, it will be understood that the triple point and critical point values w ill change depending on any impurities present within a CO2 stream. For example, the critical point of commercially acceptable sources of CO2 (i.e. containing impurities or additives) is typically a pressure of about 1,050 psig or greater and a temperature of about 80 F to about 120 F. In other embodiments, the source of CO2 has a critical point at a pressure of about 1,150 psig or greater and a temperature of about 120°F or greater.

[0055] Figure 12 shows an example wherein several different CO2 streams (i.e. having differing concentrations of elements other than CO2) were evaluated to determine the location of the phase envelope wherein the stream transitions between different phases. The streams had the concentrations set forth below' in Table 1.8CORE / 1001911.007701 / 233158072.11001911.007701Table 1

[0056] This figure demonstrates that the phase envelope and critical point follow a similar pattern, but represent slightly different values depending on the purity of the CO2 stream.

[0057] Although reference is made herein to a "dense CO2," it will be understood that this is intended to reference CO2 present in either the dense phase (i.e. above the critical pressure, but below the critical temperature) or the supercritical phase (i.e. above the critical temperature and critical pressure). As described elsewhere herein, one goal of the present disclosure is to provide methods and systems for producing a gaseous CO2 product from a source of non-gaseous CO2 (e.g., dense phase or supercritical phase CO2), while realizing cost / energy savings by using hot combustion gas for the letdown process. Therefore. CO2CORE / 1001911.007701 / 233158072.11001911.007701present in either the dense phase or the supercritical phase may form the feed stream ("source of dense CO2").

[0058] In certain embodiments, the dense CCh(e.g., supercritical phase CO2) is present at a pressure above the critical pressure and a temperature above the critical temperature. For example, a pressure of about 1,050 psig or greater and a temperature of about 85°F or greater. In other embodiments, the dense CO2 is present at a pressure above the critical pressure and a temperature below the critical temperature. For example, a pressure of about 1,050 psig or greater and a temperature of about 85 F or less.

[0059] In certain specific embodiments, the dense CO2(e.g., supercritical phase CO2) is at a pressure of about 1,050 psig or greater, about 1,075 psig or greater, about 1,100 psig or greater, about 1,150 psig or greater, about 1,200 psig or greater, about 1,250 psig or greater, about 1,500 psig or greater, about 2,000 psig or greater, about 3,000 psig or greater, about 4,000 psig or greater, about 5,000 psig or greater, or about 10,000 psig or greater. For example, from about 1,050 psig to about 5,000 psig, from about 1,050 psig to about 4,000 psig, from about 1.100 psig to about 4,000 psig, from about 1,100 psig to about 3,000 psig, from about 1,100 psig to about 2,000 psig, from about 1,100 psig to about 1,750 psig, from about 1,100 psig to about 1,500 psig, or from about 1,150 psig to about 1,500 psig.

[0060] In various embodiments, the dense CO2 (e.g., supercritical phase CO2) is at a temperature of about 0°F or greater, about 10°F or greater, about 20°F or greater, about 25°F or greater, about 30°F or greater, about 35 F or greater, about 40°F or greater, about 45°F or greater, about 50°F or greater, about 55°F or greater, about 60° F or greater, about 65 °F or greater, about 70°F or greater, about 75°F or greater, about 80°F or greater, about 85°F or greater, about 90° F or greater, about 95 °F or greater, or about 100°F or greater. For example, from about 25°F to about 250°F. from about 25°F to about 200°F. from about 25°F to about 175°F, from about 25°F to about 150°F, from about 30 F to about 150°F, from about 35 F to about 150°F, from about 40°F to about 150°F, from about 45°F to about 150°F, or from about 50°F to about 150°F. In other embodiments, the dense CO2 is at a temperature of from about O F to about 250 F, from about 0°F to about 200°F, from about 0°F to about 175°F. from about O F to about 150 F, from about 0°F to about 125°F, or from about O F to about 120°F. In still further embodiments, the dense CO2 is present at a temperature of about 85°F or less, about 80°F or less, about 75°F or less, about 70°F or less, about 65°F or less, about 60°F or10CORE / 1001911.007701 / 233158072.11001911.007701less, about 55°F or less, about 50°F or less, about 45°F or less, about 40°F or less, or about 35 F or less.

[0061] In one embodiment, the dense CCh(e.g., supercritical phase CO2) is at a pressure of from about 1,050 psig to about 5,000 psig, from about 1,050 psig to about 4,000 psig, from about 1,100 psig to about 4,000 psig, from about 1,100 psig to about 3,000 psig, from about 1,100 psig to about 2,000 psig, from about 1,100 psig to about 1,750 psig, from about 1,100 psig to about 1,500 psig, or from about 1,150 psig to about 1,500 psig and a temperature of from about O F to about 250 F, from about 25°F to about 250 F, from about 25°F to about 200°F, from about 25°F to about 175°F, from about 25°F to about 150°F, from about 30 F to about 150°F. from about 35°F to about 150°F, from about 40°F to about 150°F, from about 45°F to about 150 F. or from about 50°F to about 150 F. In certain embodiments, the dense CO2 is at a pressure of about 1,250 psig and a temperature of about 35 F.

[0062] In embodiments wherein the dense CO2 is preheated in one or more heat exchangers with the hot combustion gas, the preheating step may be such that the resulting preheated dense CO2 stream is suitable for expansion into a gaseous CO2 product. In other embodiments, the preheating step may be such that the resulting preheated dense CO2 stream is suitable for expansion into an expanded CO2 stream and subsequent heating to form a gaseous CO2 product, without generating a commercially unacceptable amount of condensation within the system.

[0063] In one embodiment, the preheated dense CO2 stream is at a pressure greater than the critical point pressure and a temperature greater than the critical point temperature (i.e. in the supercritical phase). In another embodiment, the preheated dense CO2 stream CO2 is at a pressure greater than the critical point pressure and a temperature lower than the critical point temperature (i.e. in the dense phase).

[0064] In certain embodiments, the preheated dense CO2 stream is at a pressure of about 1,050 psig or greater and a temperature of 100°F or greater. In other embodiments, the preheated dense CO2 stream CO2 is at a pressure of from about 1,050 psig to about 5,000 psig, from about 1,050 psig to about 4,000 psig, from about 1,100 psig to about 4,000 psig, from about 1,100 psig to about 3,000 psig, from about 1,100 psig to about 2,000 psig, from about 1,100 psig to about 1,750 psig, from about 1,100 psig to about 1,500 psig, or from about 1,150 psig to about 1,500 psig and a temperature of from about 100°F to about 500°F, from about 100°F to about 400°F, from about 100 F to about 300 F, from about 125°F to11CORE / 1001911.007701 / 233158072.11001911.007701about 300°F, or from about 150°F to about 300°F. In one embodiment, the preheated dense CO2 stream is at a pressure of about 1.250 psig and a temperature of about 120 F.

[0065] In certain embodiments, the gaseous CO2 product is a product suitable for use within an existing natural gas or crude oil pipeline. For example, the gaseous CO2 product may be present in a state below the maximum allowable operating pressure (MAOP) of the pipeline.

[0066] In one embodiment, the gaseous CO2 product is at a pressure and temperature below the critical point (e g., as shown in the phase diagram of Figure 11 or 12). For example, the gaseous CO2 product may be at a pressure below the critical pressure and a temperature above the critical temperature.

[0067] In one embodiment, the gaseous CO2 product is at a pressure of about 1,150 psig or less, 1,100 psig or less, 1,050 psig or less, 1,000 psig or less, 900 psig or less, 800 psig or less, 700 psig or less, 600 psig or less, or about 500 psig or less and a temperature of about 50 F or greater, about 75°F or greater, about 100°F or greater, about 125°F or greater, or about 150 F or greater. In another embodiment, the gaseous CO2 product is at a pressure of from about 250 psig to about 1,000 psig, about 300 psig to about 1,000 psig, about 300 psig to about 900 psig, about 300 psig to about 800 psig, about 400 psig to about 800 psig, about 400 psig to about 700 psig, about 400 psig to about 600 psig, or about 400 psig to about 500 psig and a temperature of from about 50°F to about 500’F, from about 75°F to about 500’F, from about 75 F to about 400°F. from about 100°F to about 400°F, from about 100 F to about 300°F, or from about 100°F to about 200°F. In certain specific embodiments, the gaseous CO2 product may be at a pressure of about 460 psig and a temperature of about 100°F.

[0068] In embodiments wherein an expanded CO2 stream is produced from the control valve and / or turbo-expander, and the expanded CO2 stream is subsequently heated to form the gaseous CO2 product, the expanded CO2 stream may be at a pressure and temperature below the critical point (e.g., as shown in the phase diagram of Figure 11 or 12). For example, the expanded CO2 stream may be at a pressure below the critical pressure and a temperature above the critical temperature.

[0069] In one embodiment, the expanded CO2 stream is at a pressure of about 1,050 psig or less and a temperature of about 25°F or greater. In one embodiment, the expanded CO2 stream may be at a pressure of about 1,100 psig or less, 1,050 psig or less, about 1,000 psig or less, 900 psig or less, 800 psig or less, 700 psig or less, 600 psig or less, about 50012CORE / 1001911.007701 / 233158072.11001911.007701psig or less, about 450 psig or less, about 400 psig or less, about 350 psig or less, or about 300 psig or less and a temperature of from about 25 F to about 500 F, from about 25 F to about 400 F, from about 25 F to about 300 F, from about 25 F to about 200 F, from about 25°F to about 150°F, from about 25°F to about 100°F, from about 25°F to about 75°F, or from about 25 F to about 50°F. In certain specific embodiments, the expanded CO2 stream may be at a pressure of about 460 psig and a temperature of about 30°F.

[0070] The processes and systems described herein reference control valves and turbo-expanders interchangeably for the expansion of the dense CO2 stream. While either device may be used to expand the dense CO2, a turbo-expander is capable of capturing some of the energy of expansion via a generator. That is, the use of a turbo-expander allows for the expansion and phase change of the dense CO2 while simultaneously allowing for the generation of energy.

[0071] In this way, the system may be characterized as a cogeneration system -wherein power is generated at the gas turbine and at the turbo-expander, and wherein cost / energy savings are realized by interconnecting the gas turbine and letdown station components. The power generated by the gas turbine and / or letdown station may be used in adjacent equipment / processes and / or sold to the electrical grid to realize further energy and cost efficiencies.

[0072] An exemplary system efficiency chart is reported below in Table 2. The theoretical results indicate that the efficiency of the combined gas turbine and letdown station may be more than twice that of a gas turbine operating independently. Example 1 corresponds to a standard gas turbine system. Example 2 corresponds to a gas turbine system with generation (i.e. as shown in Figure 2B). Example 3 corresponds to a gas turbine system with regeneration and a letdown station comprising a control valve. Example 4 corresponds to a gas turbine system with regeneration and a letdown station comprising a turbo-expander. The CO2 Heater Fuel column reports the amount of fuel that would be required to heat the dense CO2 if the hot exhaust of the gas turbine was not used for this purpose.13CORE / 1001911.007701 / 233158072.11001911.007701Table 2

[0073] As illustrated in Table 2, the combination of a gas turbine adjacent to a letdown station (i.e. use of hot exhaust gas from a gas turbine to heat CO2) results in considerable fuel savings and greatly increases the efficiency of the overall process. By operating in this manner it is possible to minimize or even eliminate the need for external power / heat to operate the letdown station and appropriately convert a dense CO2 into a gaseous CO2 product.

[0074] Turbo-expanders do encounter partial liquification of the gas phase more frequently than expansion via a control valve. This is due to an increased Joule-Thomson effect as compared to a control valve. For example, it has been observed that an inlet stream of dense CO2 at 165 F results in an outlet stream of expanded CO2 from the turbo-expander of about 29°F. Therefore, in certain embodiments comprising the use of a turbo-expander, it may be especially desirable to utilize a pre-heating step wherein the dense CO2 is preheated before expansion. Preheating results in a higher temperature outlet stream of expanded CO2 and a decreased likelihood of condensation or partial liquification in the system.

[0075] As described elsewhere herein, in certain embodiments, CO2 may be selectively removed from the hot combustion gas or any subsequent combustion gas stream. For example. CO2 may be selectively removed from the hot combustion gas, cooled combustion gas, and / or combustion gas exiting the second heat exchanger. Hot combustion gas resulting from a gas turbine can be expected to have approximately betw een 2 vol.% and 6 vol.% CO2. Therefore, it may be desirable to remove this CO2 and utilize it elsewhere in the process. In one embodiment, at least a portion of the selectively removed CO2 is combined with the source of dense CO2 and processed w ith the dense CO2 as described herein. In other14CORE / 1001911.007701 / 233158072.11001911.007701embodiments, at least a portion of the selectively removed CO2 is combined with the gaseous CO2 product. In still further embodiments, at least a portion of the selectively removed CO2 is combined with the source of dense CO2 and at least a portion of the selectively removed CO2 is combined with the gaseous CO2 product.

[0076] While various processes and systems have been described herein, it will be understood that variations of the described processes / systems are within the scope of the present disclosure.

[0077] For example, while the exemplified embodiments comprise a single preheating step (e.g., heating the dense CO2 in a first heat exchanger), it will be understood that any number of preheating steps or devices may be used. In certain embodiments, the preheating step comprise the use of 1 or more, 2 or more. 3 or more, 4 or more, 5 or more, or 10 or more heat exchangers to heat the dense CO2 prior to expansion.

[0078] In certain embodiments comprising a control valve, the process / system may be devoid of a preheating step. In other embodiments comprising a control valve, the process / system may comprise a regeneration system connected to the gas turbine system, but otherwise be devoid of a preheating system.

[0079] While various exemplified embodiments comprise a single heating step after expansion of the dense CO2, it will be understood that any number of post-heating steps or devices may be used. In certain embodiments, the expanded CO2 exiting the control valve or turbo-expander may be heated using 1 or more, 2 or more, 3 or more. 4 or more, 5 or more, or 10 or more heat exchangers to heat the expanded CO2.

[0080] In each of the above situations (i.e. when evaluating the number of preheating or post-heating steps or devices to use), it will be understood that this design decision should be guided by the goal of avoiding or minimizing contact with the phase envelope and water line of CChfor the duration of the process. For example, as illustrated in the phase diagrams of Figures 4B, 6B, and 8B, it is desirable to maintain the CO2 in the dense phase and / or supercritical phase until it is expanded to achieve gaseous CO2. During this process, it is desirable to maintain the temperature of the CO2 at a sufficiently elevated value to avoid producing the liquid phase CO2 that would result from crossing the critical point / phase envelope.

[0081] It will be understood that the present invention differs from previously know n configurations where carbon dioxide is used as a working fluid or means of heat transfer in a15CORE / 1001911.007701 / 233158072.11001911.007701closed system. For example, CN 107178436 utilized a closed system for compressing and expanding carbon dioxide as a means for generating power and exchanging heat. In contrast, the present invention is directed to an open system wherein a dense CO2 is converted to a gaseous CO2 product for subsequent transportation in pipeline or equipment that otherwise would not be suitable for the transportation of dense CO2. For example, the gaseous CO2 product may be subsequently transported in a pipeline having a maximum allowable operating pressure (MAOP) that is not suitable for transporting the source of dense CO2.

[0082] Having described the invention in detail, it will be apparent that modifications and variations are possible without departing from the scope of the invention defined in the appended claims.

[0083] When introducing elements of the present invention or the preferred embodiments(s) thereof, the articles "a", "an", "the" and "said" are intended to mean that there are one or more of the elements. The terms "comprising", "including" and "having" are intended to be inclusive and mean that there may be additional elements other than the listed elements.

[0084] In view of the above, it will be seen that the several objects of the invention are achieved and other advantageous results attained.

[0085] As various changes could be made in the above methods and systems without departing from the scope of the invention, it is intended that all matter contained in the above description and shown in the accompanying drawings shall be interpreted as illustrative and not in a limiting sense.16CORE / 1001911.007701 / 233158072.1

Claims

1001911.007701CLAIMS:

1. A process for producing a gaseous CO2 product, the process comprising:providing a source of dense CO2 and a source of hot combustion gas;contacting the dense CO2 and hot combustion gas in a first heat exchanger, thereby producing a preheated dense CO2 stream and a cooled combustion gas;expanding the preheated dense CO2 stream in a turbo-expander and / or control valve to produce an expanded CO2 stream; andcontacting the expanded CO2 stream and the cooled combustion gas in a second heat exchanger, thereby heating the expanded CO2 stream and producing a gaseous CO2 product.2 A system for producing a CO2 product, the system comprising:a source of dense CO2 and a source of hot combustion gas;a first heat exchanger configured to heat the dense CO2 with the hot combustion gas and produce a preheated dense CO2 stream and a cooled combustion gas;a turbo-expander and / or control valve for expanding the preheated dense CO2 stream to produce an expanded CO2 stream; anda second heat exchanger for heating the expanded CO2 stream from the cooled combustion gas and producing a gaseous CO2 product.

3. The process or system of claim 1 or 2, wherein at least a portion of the hot combustion gas is the exhaust gas of a gas turbine.

4. The process or system of claim 3, wherein the hot combustion gas is an exhaust gas of a gas turbine.

5. The process or system of claim 3 or 4, wherein the gas turbine is adjacent to the first heat exchanger, turbo-expander, control valve, and / or second heat exchanger.

6. The process or system of claim 5, wherein the gas turbine is within 2,000 m or less, 1,500 m or less, 1,000 m or less, 500 m or less, 250 m or less, 100 m or less, 75 m or less, 5017CORE / 1001911.007701 / 233158072.11001911.007701m or less, 25 m or less of each of the first heat exchanger, turbo-expander and / or control valve, and second heat exchanger.

7. The process or system of claim 5, wherein the gas turbine is within 2,000 m or less, 1,500 m or less, 1,000 m or less, 500 m or less, 250 m or less, 100 m or less, 75 m or less, 50 m or less, 25 m or less of the first heat exchanger.

8. The process or system of any one of claims 1 to 7, wherein the dense CO2 is a supercritical phase CO2 at a pressure greater than the critical point pressure and a temperature greater than the critical point temperature.

9. The process or system of any one of claims 1 to 7, wherein the dense CO2 is at pressure greater than the critical point pressure and a temperature lower than the critical point temperature.

10. The process or system of any one of claims 1 to 7, wherein the dense CO2 is at a pressure of from about 1,050 psig to about 5,000 psig and atemperature of between about 0°F and about 250°F.

11. The process or system of any one of claims 1 to 10. wherein the preheated dense CO2 stream is at a pressure greater than the critical point pressure and a temperature greater than the critical point temperature.

12. The process or system of any one of claims 1 to 10. wherein the preheated dense CO2 stream is at a pressure greater than the critical point pressure and a temperature lower than the critical point temperature.

13. The process or system of any one of claims 1 to 10. wherein the preheated dense CO2 stream is at a pressure of from about 1,050 psig to about 5,000 psig and a temperature of from about 100°F to about 500°F.18CORE / 1001911.007701 / 233158072.11001911.00770114. The process or system of any one of claims 1 to 13, wherein the gaseous CO2 product is at a pressure below the critical pressure and a temperature above the critical temperature.

15. The process or system of any one of claims 1 to 13, wherein the gaseous CO2 product is at a pressure of about 1,100 psig or less and a temperature of about 50°F or greater.

16. The process or system of any one of claims 1 to 13, wherein the gaseous CO2 product is at a pressure of from about 250 psig to about 1,000 psig and a temperature of from about 50°F to about 500°F.

17. The process or system of any one of claims 1 to 16, further comprising selectively removing CO2 from the hot combustion gas, cooled combustion gas, and / or combustion gas exiting the second heat exchanger.

18. The process or system of claim 17, wherein at least a portion of the selectively removed CO2 is combined with the source of dense CO2 and / or combined with the gaseous CO2 product.

19. The process or system of any one of claims 1 to 18, wherein the gaseous CO2 product is transported in a pipeline having a maximum allowable operating pressure (MAOP) that is not suitable for transporting the source of dense CO2.

20. The process or system of claim 19, wherein the pipeline is a natural gas and / or crude oil pipeline.19CORE / 1001911.007701 / 233158072.1

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